Systems for generating energy from geothermal sources and methods of operating and constructing same

ABSTRACT

The present disclosure describes a system and a method for generating energy from geothermal sources. The system includes an injection well and a production well extending underground into a rock formation, a first lateral section connected to the injection well and a second lateral section connected to the production well, the first and second lateral sections connected with a multilateral connector, defining a pressure-tested downhole well loop within the rock formation and in a heat transfer arrangement therewith. The downhole well loop cased in steel and cemented in place within the rock formation. The downhole well loop to receive working fluid capable of undergoing phase change between liquid and gas within the downhole well loop as a result of heat transferred from the rock formation. The system also includes a pump to circulate working fluid, a turbine system to convert the flow of working fluid into electricity, and a cooler.

FIELD OF INVENTION

The present disclosure relates generally to generating energy fromgeothermal sources and more specifically to systems for generatingenergy from geothermal sources and methods of operating and constructingsame.

BACKGROUND OF THE INVENTION

Systems for energy generation from geothermal sources (also referred toherein as geothermal energy generation systems) are designed such thatworking fluids or water are circulated underground to be heated, andthen the heat energy is brought back up to the surface to be convertedinto electricity. The working fluid or water is then cooled and returnedunderground to the heat source.

In some known geothermal energy generation systems, the working fluidthat flows underground is exposed to the rock formations underground,allowing the first working fluid to pick up debris, rocks, and othersolids as it flows underground. The picking up of debris, rocks, andother solids may cause issues with any equipment with moving parts, suchas pumps that are required to help circulate the working fluid, orturbines which are used to generate electricity from the heat energyfrom the working fluid when returning to the surface.

One method of solving this is to provide filters along the flow path ofthe working fluid, or prior to the working fluid entering any machinery.The filters may help mitigate the working fluid from carrying debris orsolids into any machinery. However, filters need to be changed, andhence increase maintenance cost. Furthermore, filters are an addedcomponent, and as such, lead to another potential point of failure inthe system.

Another method of solving the issue of debris in the working fluid is touse a binary cycle power station, where two working fluids are used,where a first working fluid is heated underground, and then is passed byan isolated secondary working fluid in a second loop, where the secondworking fluid is heated and is used to power turbines. While this maysave the turbines from encountering debris, the pumps required tocirculate the first working fluid underground still need to contend withthe debris. In addition, binary cycle power stations are not efficient,as they have a high parasitic load, and a significant amount of heat maybe loss when transferring heat from the first working fluid to thesecond working fluid.

Furthermore, the working fluid that loops underground may also begineroding away at the rock surfaces along the path of the flow of theworking fluid. The erosion of the rock surfaces may lead to unstablepathways underground, and may also lead to the damage of theenvironment. As such, to prevent erosion, the flow rates of the workingfluid must be minimized to protect the integrity of the rock formations.This will lead to addition residence time underground for the workingfluid.

As the working fluid flows underground, it may also leak into thesurrounding environment through gaps in the rock formations underground,causing underground pollution. As such, in order to be environmentallyfriendly, the working fluid needs to be an environmentally friendlyfluid such as water. Even so, if the first working fluid picks up anynon-environmentally friendly substances along it's path flow, such aspicking up oil while flowing through a pump, this may still be leakedinto the external environment.

In other known geothermal energy systems, to prevent erosion,environmental leakage and to prevent the inclusion of debris in theworking fluid along the loop underground, a chemical layer, a chemicallytreated layer, or a polymer coating layer is provided, where the polymercoating is applied to and seals the rock formation from the circulatingfluid. However, some inherent shortcomings with a polymer coating layerinclude the polymer coated loop underground not being able to bepressure tested. Without pressure testing the underground loop, there isno assurance as to whether the polymer coating layer will hold at depthswhere the working fluid is subjected to high pressures and whether thepolymer coating layer will react with different working fluids, and assuch, there may be leaks including underground pollution.

Furthermore, a polymer coating itself is subject to erosion, and onceeroded may allow for erosion of the rock formation. This leads tocontamination of the first working fluid. To prevent this, the polymercoating may need to be applied in several layers, and may also need tobe continually replaced, leading to high maintenance costs, additionaldowntime, and loss of production time. Even after applying the polymercoating, it is difficult to verify that the entire rock formation andpathway/loop of the first working fluid has been coated, much lessensuring the thickness or integrity of the polymer coating.

In other prior art, such as U.S. Patent Application Publication No.2018/0291880 and International Patent Application Publication No. WO2022029699 a casing is provided, however, this casing is not cemented,which may lead to instability. In addition, this casing is not pressuretested, which may lead to instabilities at depths with high pressures orwith working fluids with either high or varied flowrates underground.The instabilities may result in poor operating performance as well aspotentially underground pollution, should a working fluid that is notwater leak, such as is provided in both of the aforementioned patentapplication publications, where two working fluids are used. Undergroundpollution may occur through leakage of the working fluids into gaps inthe rock formation. The gaps in the rock formation may be unknownfractures that were previously present, or may be fractures that wereinduced through drilling during the construction of the geothermalenergy generation system. If there is any leakage of working fluid, thefluid may be transported through the fractures, and into sensitiveresources, such as the ground water.

In other prior art, such as U.S. Patent Application Publication No.2011/0048005, a continuous string of pipe is cemented within andthroughout the length of two connected wellbores, specifically from aninjection wellhead of one borehole, underground to a subterranean nearlyhorizontal pipeline, and back up an ascending well to a productionwellhead. This allows for a working fluid to be transported underground,undergo a phase change due to the heat from the surrounding subterraneanrock, and then transported back to the surface to be used in the powerplant. There is only a single subterranean horizontal pipeline linkingbetween the injection wellhead and production wellhead. In this type ofsystem, the single subterranean horizontal pipeline and the distancebetween the injection wellhead and production wellhead tends to be quitelong in order to effect sufficient heat transfer between the rockformation and the production fluid. This large distance between theinjection wellhead and production wellhead tends to create a largefootprint both above ground and below ground. This increases the cost ofthe system overall, as there is additional length of piping requiredabove ground between the injection wellhead and the production wellhead,additional volumes of working fluid for the additional lengths of pipingabove ground, and also heat may be lost due to the additional time thatthe production fluid is spent above ground, potentially increasingparasitic load. Furthermore, the construction technique provided in U.S.Patent Application Publication No. 2011/0048005 does not allow for apressurized connection between two sections.

As such, it would be advantageous to have a solution where thegeothermal energy generation system may have an underground loop thatincludes a barrier that may be pressure tested, and one where the riskof erosion, inclusion of debris and leakage into the surrounding rockformations and environment are at a minimal. In addition, it would alsobe beneficial to have a solution where maintenance is minimal, savingcosts and minimizing downtime, and where there are fewer points offailure within the system.

SUMMARY OF INVENTION

According to various aspects of the present invention, there is provideda system for generating energy from geothermal sources. The systemincludes an injection well extending underground into a rock formation,the injection well having an upper end and a lower end. The system alsoincludes a production well extending underground into the rock formationin proximity to the injection well, the production well having an upperend and lower end. Furthermore, the system includes a first lateralsection connected to and extending away from a location along theinjection well and a second lateral section connected to and extendingaway from a location along the production well, where the first andsecond lateral sections are connected with a multilateral connector,each of the first and second lateral sections having a length that isgreater than the distance between the upper ends of the injection welland the production well. Each of the injection well, the productionwell, the first and second lateral sections being cased in steel andcemented in place within the rock formation. The injection well, thefirst lateral section, the multilateral connector, the second lateralsection and the production well cooperating with each other to define apressure-tested downhole well loop within the rock formation and in aheat transfer arrangement therewith, the pressure-tested downhole wellloop being configured to receive a working fluid capable of undergoingphase change between liquid and gas within the pressure-tested downholewell loop as a result of heat transferred from the rock formation. Thesystem also includes a pump fluidly connected to the injection well, thepump being configured to circulate the working fluid through thepressure-tested downhole well loop. In addition, the system includes aturbine system fluidly connected to the production well, the turbinesystem being operable to convert mechanical energy generated from theflow of working fluid, into electricity. The system further includes acooler fluidly connected between the pump and the turbine system forcooling the working fluid.

The system may further include an injection well surface casingsurrounding an inlet of the injection well, where the injection wellsurface casing is partially above the surface and being configured toprevent the escape of the working fluid into the rock formation.

The system may further include a production well surface casingsurrounding an outlet of the production well, the production wellsurface casing partially above the surface and being configured toprevent the escape of the working fluid into the rock formation.

The injection well includes an inlet, and the production well includesan outlet, the inlet and the outlet being located on the surface inproximity to each other, the inlet being at a distance between 7 m and50 m from the outlet.

The system may have an above ground surface area of 22500 m².

The working fluid may be a homogeneous working fluid.

Alternatively, the working fluid may be a heterogenous working fluid.

The injection well may have a depth of between 1000 m and 4000 m.

The first lateral section may have a length of between 2000 m to 4000 m.

The second lateral section may have a length of between 2000 m to 4000m.

The production well may have a depth of between 1000 m to 4000 m.

The first lateral section may be longer than the second lateral section,and wherein the first lateral section is at a lower depth than that ofthe second lateral section.

The first lateral section may be at the same depth as the second lateralsection, the first lateral section extending away from the lower end ofthe injection well at a first angle, and the second lateral sectionextending away from the lower end of the production well at a secondangle.

In operation the pressure-tested downhole well loop may be configured toreceive fluids pressurized between 7 MPa and 31 MPa.

The pressure-tested downhole well loop may be capable to withstandpressures of at least 7 MPa.

The pump may be a positive displacement type pump with a variable speeddrive controller.

In addition, the positive displacement type pump may be selected fromthe group consisting of plunger type pumps, gear type pumps and rotaryvane type pumps.

The turbine system may include a turbine expander.

The turbine system may be capable of generating between 0.5 to 2 MW ofoutput power.

The cooler may be using ambient air as a coolant.

The system may further include a storage tank, the storage tankconnected between the cooler and the pump, and being configured to holdthe excess working fluid.

The working fluid may be selected from the group consisting of arefrigerant, a hydrocarbon-based fluid, ammonia, carbon dioxide, andwater.

In addition, if the working fluid is a hydrocarbon-based working fluid,the hydrocarbon-based working fluid is selected from the groupconsisting of propane, ethane, pentane, butane, and hydrocarbon blend.

Alternatively, the working fluid is propane.

The system may further include a recuperator with a first flow throughconnected between the turbine system and the cooler, and a second flowthrough connected between the pump and the injection well, therecuperator being configured to transfer heat from the first flowthrough to the second flow through.

Furthermore, the system may include an access well having a lateralsegment, wherein the multilateral connector is positioned within thelateral segment of the access well.

The system may also include, wherein the injection well is a firstinjection well, the production well is a first production well, themultilateral connector is a first multilateral connector, thepressure-tested downhole well loop is a first pressure-tested downholewell loop and the pump is a first pump, a second injection wellextending underground into the rock formation, the second injection wellhaving an upper end and a lower end. In addition, the system may alsoinclude a second production well extending underground into the rockformation in proximity to the second injection well, the secondproduction well having an upper end and lower end. Furthermore, thesystem may include a third lateral section connected to and extendingaway from a location along the second injection well, and a fourthlateral section connected to and extending away from a location alongthe second production well, where the third and fourth lateral sectionsconnected with a second multilateral connector, each of the third andfourth lateral sections having a length that is greater than thedistance between the upper ends of the second injection well and thesecond production well. In addition, each of the second injection well,the second production well, the third and fourth lateral sections beingcased in steel and cemented in place within the rock formation. Thesecond injection well, the third lateral section, the secondmultilateral connector, the fourth lateral section and the secondproduction well cooperating with each other to define a secondpressure-tested downhole well loop within the rock formation and in aheat transfer arrangement therewith, the second pressure-tested downholewell loop being configured to receive the working fluid capable ofundergoing phase change between liquid and gas within the secondpressure-tested downhole well loop as a result of heat transferred fromthe rock formation. The system may also include a second pump fluidlyconnected to the second injection well, the second pump being configuredto circulate the working fluid through the second pressure-testeddownhole well loop. In addition, the system may include the secondproduction well fluidly connected to the turbine system, the turbinesystem being configured to receive the working fluid from the firstproduction well of the first pressure-tested downhole well loop and thesecond production well of the second pressure-tested downhole well loop.The cooler may be fluidly connected to both the first pump connected tothe first injection well, and the second pump connected to the secondinjection well, and the second multilateral connector of the secondpressure-tested downhole well loop being positioned within the lateralsegment of the access well at a location spaced apart from the firstmultilateral connector.

In addition, the first injection well includes a first inlet, the firstproduction well includes a first outlet, the second injection wellincludes a second inlet, and the second production well includes asecond outlet, the second inlet and the second outlet being located onthe surface in proximity to each other, the second inlet being at adistance between 7 m and 50 m from the second outlet.

Furthermore, the first inlet and the second inlet may be located on thesurface in proximity to each other, the first inlet being at least adistance of 20 m from the second inlet.

In addition, the first outlet and the second outlet may be located onthe surface in proximity to each other, the first outlet being at leasta distance of 20 m from the second outlet.

The system may further have an above ground surface area of 45000 m².

According to various aspects of the present invention, there is provideda method of generating energy from geothermal sources. The methodincluding providing a pressure-tested downhole well loop extendingunderground into a rock formation, the pressure-tested downhole wellloop including an injection well, a production well in proximity to theinjection well, a first lateral section connected to the injection well,a second lateral section connected to the production well, amultilateral connector connecting the first lateral section and thesecond lateral section, where each of the injection well, the productionwell, the first and second lateral sections being cased in steel andcemented in place within the rock formation, the first and secondlateral sections having a length that is greater than the distance onthe surface between the injection well and the production well. Themethod includes conveying a working fluid through the pressure-testeddownhole well loop, the working fluid being received by the injectionwell in a liquid state. While conveying the working fluid through thepressure-tested downhole well loop, transferring heat from thesurrounding rock formations to the liquid working fluid and exertingpressure on the liquid working fluid. The method further includesinducing a phase change in the working fluid from a liquid state to agaseous state, the working fluid exiting the production well in agaseous state. In addition, the method includes converting themechanical energy generated from the flow of the gaseous working fluid,into electricity. The method also includes cooling the working fluid andinducing a phase change in the working fluid to a liquid state, andreturning the working fluid to the injection well.

Conveying the working fluid through the pressure-tested downhole wellloop may include pumping the working fluid.

Exerting pressure on the liquid working fluid may include exertingbetween 7 MPa and 31 MPa on the liquid working fluid.

The step of converting the mechanical energy generated from the flow ofthe gaseous working fluid into electricity may generate between 0.5 to 2MW of output power.

The step of cooling the working fluid and inducing a phase change in theworking fluid may be cooled using a cooler.

The method may include storing excess working fluid in a storage tank.

The working fluid may be a homogenous working fluid.

Alternatively, the working fluid may be a heterogenous working fluid.

The working fluid may be selected from the group consisting of arefrigerant, a carbon-based fluid, ammonia, carbon dioxide, and water.

If the working fluid is a hydrocarbon-based working fluid, thehydrocarbon-based working fluid may be selected from the groupconsisting of propane, ethane, pentane, butane, and hydrocarbon blend.

Alternatively, the working fluid is propane.

Where the working fluid is propane, the propane may be received by theinjection well having a temperature of between 10° C. and 40° C. and apressure of between 1000 kPag and 2000 kPag.

Alternatively, the propane may be received by the injection well havinga temperature of 20° C. and a pressure of 1300 kPag.

Where the working fluid is propane, the step of inducing a phase changein the propane from a liquid state to a gaseous state may occur when thepropane reaches a temperature of 140° C. and a pressure of 6250 kPag.

In addition, inducing a phase change in the propane from a liquid stateto a gaseous state may occur in one of the second lateral section andthe production well.

The propane exiting the production well in a gaseous state may have atemperature of between 90° C. and 110° C. and a pressure of between 3000kPag and 4000 kPag.

Alternatively, the propane exiting the production well in a gaseousstate may have a temperature of 106° C. and a pressure of 3500 kPag.

While conveying the working fluid through the pressure-tested downholewell loop, the temperature of the propane may increase by 76° C. and thepressure of the propane may increase by 2170 kPag.

After converting the mechanical energy generated from the flow of thegaseous working fluid into electricity, the propane may have atemperature of between 16° C. and 63° C. and a pressure of between 700kPag and 1500 kPag.

Cooling the working fluid may cool the propane to a temperature of 30°C. and a pressure of 1080 kPag.

The method may include transferring heat from the working fluid in afirst region to the working fluid in a second region using arecuperator, the working fluid in the first region occurring between thesteps of converting the mechanical energy generated from the flow of thegaseous working fluid and cooling the working fluid, the working fluidin the second region occurring between the steps of conveying theworking fluid through the pressure-tested downhole well loop and theworking fluid being received by the injection well in the liquid state.

According to various aspects of the present invention, there is provideda method of constructing a pressure-tested downhole well loop for asystem for generating energy from geothermal sources, thepressure-tested downhole well loop being configured to transfer heatfrom the surrounding rock formations to a working fluid flowing withinthe pressure-tested downhole well loop, and induce a phase change on theworking fluid from a liquid state to a gaseous state. The methodincludes providing an access well extending underground into a rockformation, and drilling an injection well into the underground rockformation, the injection well spaced apart from the access well. Themethod further includes drilling a first lateral section extending awayfrom the injection well and connecting to the access well and installinga first steel casing for the injection well and the first lateralsection. In addition, the method includes cementing the first steelcasing for the injection well and the first lateral section in placewithin the rock formation and drilling a production well into theunderground rock formation, the production well in proximity to theinjection well. The method also includes drilling a second lateralsection extending away from the production well towards a connectingpoint between the first lateral section and the second lateral section,the connecting point located along the access well adjacent to the firstlateral section and installing a second steel casing for the productionwell and the second lateral section. Furthermore, the method includesproviding a multilateral connector through the access well andinstalling the multilateral connector at the connecting point betweenthe first and second lateral sections and pressure testing the downholewell loop, the downhole well loop including the injection well, thefirst lateral section, the multilateral connector, the second lateralsection, and the production well, the first and second lateral sectionshaving a length that is greater than the distance on the surface betweenthe injection well and the production well. The method also includescementing the second steel casing for the production well and the secondlateral section to the rock formation.

The method may also include drilling a hole for an injection wellsurface casing prior to drilling the injection well and setting in placethe injection well surface casing.

Cementing the first casing for the injection well and the first lateralsection in place within the rock formation may include drilling abridging hole at an intersection point between the first lateral sectionand the second lateral section, and drilling the second lateral sectionmay include connecting the second lateral section to the bridging hole.

The method may also include installing a first isolation packer and afirst cementing stage tool prior to cementing the first casing for theinjection well and the first lateral section in place within the rockformation, the first isolation packer and the first cementing stage toolinstalled in proximity to the intersection point between the firstlateral section and the access well, the first isolation packerinstalled around an outer diameter of the first casing, and the firstcementing stage tool installed within and blocking an inner diameter ofthe first casing.

Drilling the second lateral section extending away from the productionwell towards the connecting point may include installing a whipstockwithin the first lateral section in proximity to the connection point.

The method may further include drilling a hole for a production wellsurface casing prior to drilling the production well and setting inplace the production well surface casing.

Pressuring testing the downhole well loop may include subjecting thedownhole well loop to the pressure at the greatest depth within downholewell loop.

The method may include installing a second isolation packer and a secondcementing stage tool prior to cementing the second casing for theproduction well and the second lateral section in place within the rockformation, the second isolation packer and the second cementing stagetool installed in proximity to the intersection point between the secondlateral section and the multilateral connector, the second isolationpacker installed around the outer diameter of the second casing, and thesecond cementing stage tool installed within and blocking the innerdiameter of the second casing.

According to various aspects of the present invention, there is provideda system for generating energy from geothermal sources. The systemincludes a first injection well and a second injection well extendingunderground into a rock formation, each of the first and secondinjection well having an upper end and a lower end. The system includesa first production well and a second production well extendingunderground into the rock formation, each of the first and secondproduction well in proximity to both the first and second injectionwell, each of the first and second production well having an upper endand lower end. The system also includes a first lateral sectionconnected to and extending away from a location along the firstinjection well, a second lateral section connected to and extending awayfrom a location along the first production well, a third lateral sectionconnected and extending away from a location along the second injectionwell, and a fourth lateral section connected to and extending away froma location along the second production well. The first and secondlateral sections connected with a first multilateral connector, each ofthe first and second lateral sections having a length that is greaterthan the distance between the upper ends of the first injection well andthe first production well, and the third and fourth lateral sectionsconnected with a second multilateral connector, each of the third andfourth lateral sections having a length that is greater than thedistance between the upper ends of the second injection well and thesecond production well. In addition, each of the first and secondinjection wells, the first and second production wells, the first,second, third and fourth lateral sections being cased in steel andcemented in place within the rock formation. The system also includesthe first injection well, the first lateral section, the firstmultilateral connector, the second lateral section and the firstproduction well cooperating with each other to define a firstpressure-tested downhole well loop within the rock formation, the secondinjection well, the third lateral section, the second multilateralconnector, the fourth lateral section and the second production wellcooperating with each other to define a second pressure-tested downholewell loop within the rock formation, being in a heat transferarrangement with the rock formation each of the first and the secondpressure-tested downhole well loop being configured to receive a workingfluid capable of undergoing phase change between liquid and gas as aresult of heat transferred from the rock formation. The system furtherincludes a first pump fluidly connected to the first injection well, thefirst pump being configured to circulate the working fluid through thefirst pressure-tested downhole well loop, and a second pump fluidlyconnected to the second injection well, the second pump being configuredto circulate the working fluid through the second pressure-testeddownhole well loop. The system also includes a turbine system fluidlyconnected to the first and second production wells, the turbine systembeing operable to convert mechanical energy generated from the flow ofworking fluid, into electricity. Furthermore, the system includes acooler fluidly connected between the first and second pumps and theturbine system, the cooler being operable to cool the working fluidreceived from the turbine system and to provide the cooled working fluidto both the first and second pumps, and where the first and secondpressure-tested downhole well loop located in proximity to each other.

According to various aspects of the present invention, there is provideda system for generating energy from geothermal sources. The systemincludes an injection well extending underground into a rock formation,the injection well having an upper end and a lower end. The system alsoincludes a production well extending underground into the rock formationin proximity to the injection well, the production well having an upperend and lower end. The system further includes a first lateral sectionconnected to and extending away from a location along the injectionwell, and a second lateral section connected to and extending away froma location along the production well. The first and second lateralsections are connected with a multilateral connector. Each of theinjection well, the production well, the first and second lateralsections being cased in steel and cemented in place within the rockformation. The system also includes the injection well, the firstlateral section, the multilateral connector, the second lateral sectionand the production well cooperating with each other to define apressure-tested downhole well loop within the rock formation and in aheat transfer arrangement therewith, the pressure-tested downhole wellloop being configured to withstand a pressure of at least 7 MPa andreceive a working fluid capable of undergoing phase change betweenliquid and gas within the pressure-tested downhole well loop as a resultof heat transferred from the rock formation. The system also includes apump fluidly connected to the injection well, the pump being configuredto circulate the working fluid through the pressure-tested downhole wellloop. Furthermore, the system includes a turbine system fluidlyconnected to the production well, the turbine system being operable toconvert mechanical energy generated from the flow of working fluid, intoelectricity, and a cooler fluidly connected between the pump and theturbine system for cooling the working fluid.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

The embodiments of the present invention shall be more clearlyunderstood with reference to the following detailed description of theembodiments of the invention taken in conjunction with the accompanyingdrawings, in which:

FIG. 1 is a schematic cross-sectional view showing a system forgenerating energy from geothermal sources in accordance with anembodiment;

FIG. 2 is a conceptual schematic view of the system for generatingenergy from geothermal sources shown in FIG. 1 ;

FIG. 3 is another conceptual schematic view of a system for generatingenergy from geothermal sources in accordance with an alternateembodiment to that shown in FIG. 2 ;

FIG. 4 is a flow chart setting out the steps of a method of generatingenergy from geothermal sources in accordance with the embodiment shownin FIG. 2 ;

FIG. 5 is a flow chart setting out the steps of an alternate method ofgenerating energy from geothermal sources in accordance with theembodiment shown in FIG. 3 ;

FIG. 6A is a schematic cross-sectional view showing an alternateembodiment of a system for generating energy from geothermal sourceswith two fully cased downhole well loops connected to a single accesswell in accordance with an embodiment;

FIG. 6B is a conceptual schematic view of the embodiment of the systemfor generating energy from geothermal sources of FIG. 6A, where twofully cased downhole well loops are fluidly connected to a singleturbine system and single cooler, and where the working fluid ispropane;

FIG. 7 is a schematic cross-sectional view depicting an initial step ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 , showing the drilling of the injection well, aconstruction well and a first lateral connecting section;

FIG. 8 is a schematic cross-sectional view depicting a second step ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 , showing the casing being installed along the injectionwell and through part of the first lateral connection section;

FIG. 9 is a schematic cross-sectional view depicting a third step ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 , showing an isolation packer and cementing stage toolbeing installed, and cement being poured between the casing and thewalls of the injection well and part of the first lateral connectionsection;

FIG. 10 is a schematic cross-sectional view depicting a fourth step ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 , showing a two-part whipstock being installed inproximity to the isolation packer, and the drilling of the wellbore holefor the production well;

FIG. 11 is a schematic cross-sectional view depicting a fifth step ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 , showing the drilling of the production well, a secondlateral connecting section, and an open hole of the casing window of thetwo-part whipstock;

FIG. 12 is a schematic cross-sectional view depicting a sixth step ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 , showing the removal of the core of the two-partwhipstock, leaving a window guide installed between the two lateralconnecting sections, and the installation of the casing along theproduction well, second lateral connecting section and the open hole ofthe casing window of the two-part whipstock;

FIG. 13 is a schematic cross-sectional view depicting a seventh step ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 , showing the installation of a multilateral connectoralong the window guide between the two lateral connecting sections, andthe connection of the injection well and the production well through thetwo lateral connecting sections and the multilateral connector;

FIG. 14 is a schematic cross-sectional view depicting an eighth step ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 , showing the installation of an isolation packer andcementing stage tool along the open hole of the casing window of thetwo-part whipstock, and the pouring of cement between the casing and thewalls of the production well, the second lateral connecting section andthe open hole of the casing window of the two-part whipstock;

FIG. 15 is a flow chart setting out the steps of a method ofconstructing the system for generating energy from geothermal sourcesshown in FIG. 1 in accordance with an embodiment of the invention.

DESCRIPTION OF THE PREFERRED EMBODIMENTS OF THE INVENTION

The description, which follows, and the embodiments described thereinare provided by way of illustration of an example, or examples ofparticular embodiments of principles and aspects of the presentinvention. These examples are provided for the purposes of explanationand not of limitation, of those principles of the invention. In thedescription that follows, like parts are marked throughout thespecification and the drawings with the same respective referencenumerals.

By way of general overview, there is provided a system for generatingenergy from geothermal sources 100 (also referred to herein as ageothermal energy generation system 100) with single heat exchange loop,where the system 100 includes a fully cased, pressure tested andcemented downhole well loop 108 (also referred to herein as a fullycased downhole well loop 108) for isolating and circulating a singlefluid 200 (also referred to as a working fluid 200) over an extendedlength underground to achieve heat exchange between the working fluid200 and heat emanating/radiating from the earth (i.e. the undergroundheat source). The system 100 employs a Rankine cycle (preferably, anorganic Rankine cycle) to convert the energy stored in the heatedworking fluid 200 into mechanical energy which is then used to generateelectrical power.

A person skilled in the art will recognize that in a Rankine cycle,working fluid 200 may undergo phase changes. For clarity, in thedescription below, working fluid 200 will be generally referred toregardless of the state of matter. Working fluid 200 in a liquid statewill be referred to as liquid working fluid 204, and working fluid 200in a gaseous state will be referred to as gaseous working fluid 208.

The geothermal energy generating system 100 includes, below ground, thefully cased downhole well loop 108 in the nature of a vertical injectionwell 112 extending into the ground; a first lower lateral section 116connected to, and extending away from, the vertical injection well 112;and a vertical production well 128 extending into the ground; and asecond upper lateral section 124 connected to, and extending away from,the vertical production well 128. The first and second lateral sections116, 124 meet at a juncture where a multilateral connector 120 isinstalled. Above ground, the geothermal energy generating system 100includes a pump 104 fluidly connected to the injection well 112, that isconfigured to move the liquid working fluid 204 down the injection well112 away from the surface 316, through the first lower lateral section116, the multilateral connector 120 and the second upper lateral section124, and then up the production well 128 back towards the surface 316.The liquid working fluid 204 undergoes a phase change while underground,and returns to the surface 316 through the production well 128 as agaseous working fluid 208 where it flows into a turbine system 132 forpower generation. Within the turbine system 132 the gaseous workingfluid 208 spins a turbine that then rotates a shaft and, creatingmechanical energy. This mechanical energy is converted to electricity bya shaft driven power generator (not shown). Also provided, is a cooler136 that is fluidly connected to the turbine system 132. The cooler 136condenses the low pressure gaseous working fluid 208 after it leaves theturbine system 132, returning it to its original liquid state wherein itmay be pumped down the injection well 112 and circulated through thefully cased downhole well loop 108.

As will be appreciated by a person skilled in the art and apparent fromthe description that follows, the geothermal energy generation system100 disclosed tends to address the challenges identified above. Morespecifically, use of the fully cased downhole well loop 108 removes anyrisk of cross contamination between the working fluid 200 flowingthrough the fully cased downhole well loop 108, and any rock formations320 or formation fluids and any risk that the working fluid 200 willerode the rock formations 320, since the working fluid 200 never comesinto contact with the rock formations 320. The velocity of the workingfluid 200 may also be greater within fully cased downhole well loop 108,as there is no risk of erosion of rock formations 320 due to the lack ofcontact. In addition to preventing the erosion of the wellbore walls theaddition of casing also eliminates the risk of wellbore instability androck mass failure due to the in-situ and induced stresses around thewellbore. In prior art systems, in order to achieve minimal crosscontamination, the velocity of the working fluid must be carefullymanaged and monitored to ensure that there is minimal erosion on anywellbores or underground sections. Ensuring that there is minimal to noerosion is important, not just from the perspective of preserving theenvironment, but also to avoid creating instabilities in rock formations320 that could lead to earthquakes or other potential consequences.Furthermore, because working fluid 200 is isolated from rock formations320, there is no risk of dissolving of minerals or other substances thatmay change the composition of working fluid 200. In other prior artwhere the working fluid 200 may be in contact with the surrounding rockformations 320, there is a risk of dissolving minerals or othersubstances that the working fluid 200 may come into contact with,especially while working fluid 200 erodes at the rock formation 320surfaces, and undergoes heat changes. The dissolving of minerals mayalso lead to the depositing of said minerals in pipes or othercomponents of the geothermal energy generating system 100 when workingfluid 200 cools, creating blockages and adding maintenance to system100.

Fully cased downhole well loop 108 is pressure tested and is cemented tothe surrounding rock formation 320 underground. Due to its construction,any working fluid 200 finding its way out of fully cased downhole wellloop 108 is greatly minimized. As such, the risk of any working fluid200 leaking or finding its way out of the fully cased downhole well loop108 and potentially causing pollution or other environmental concerns isgreatly minimized, especially when working fluid 200 undergoessignificant changes in temperature and pressure. In contrast, otherprior art systems may suffer fluid losses due to leak off into formationand/or fluid contamination from influxes of formation fluids due to theworking fluid not being fully isolated from the rock formations 320.This would be from not being cased including being unable tosuccessfully obtain a valid pressure test. As a result, the fully caseddownhole well loop 108 can use non-conventional working fluids 200 withdifferent thermal capacities, and different phase transition points,hence allowing for potentially more energy efficient systems, greaterpower generation, and geothermal generation systems with smallerfootprints, while reducing the concern of contaminating the environment.Furthermore, parasitic power loss is minimized. A person skilled in theart will recognize that parasitic losses may be described as theabsorbed power being the energy required to operate pumps, cooler fansand other loads, reducing the net energy output of a system. A personskilled in the art will also recognize that net energy is power producedsubtracted by power used to operate the system.

The casing material for fully cased downhole well loop 108 may be steel.Unlike in other prior art, where a chemical liner may be used, steelbeing a hardened and inert material, along with the support of thecement may withstand high pressures. Furthermore, there is a lesser riskof steel chemically interacting with working fluid 200, allowing for agreater selection of working fluid 200 for the geothermal energygenerating system 100. In addition, the construction and application ofa steel casing is substantially safer in comparison with a chemicalliner when ensuring that there are no leaks within fully cased downholewell loop 108.

By using a single heat exchange loop with a single working fluid 200, asopposed to two loops with two working fluids, there is a significantreduction in parasitic loss of energy, as the heat is retained in thesingle working fluid 200 and is not lost to the environment in anytransfers of heat when there are multiple working fluids.

Additionally, as working fluid 200 is fully contained within thegeothermal energy generating system 100, the working fluid 200 may beeasily changed if environmental conditions change. For example, if thetemperature underground changes, the working fluid 200 can be easilyreplaced with another working fluid 200 with a lower boiling point. Thisallows the geothermal energy generating system 100 to continue tooperate without the need for structural changes, such as adjusting thedepth of the lateral sections to obtain the heat required.

Providing two lateral sections underground with a multilateral connectorto connect the two lateral sections, allows for the injection well 112and production well 128 to be in relatively close proximity to eachother. As such, the geothermal energy generating system 100 tends tooccupy a smaller footprint, both underground and the above groundsurface area, as compared to other prior art systems. The smallerfootprint may lead to reduced capital and operating costs. For example,U.S. Patent Application Publication No. 2011/0048005, has a singlehorizontal pipeline underground. This leads to the injection wellheadand the production wellhead being at significantly larger distances awayfrom each other and hence occupying a larger footprint than theembodiments described below. The larger footprint may lead toinefficiencies in heat transfer and significant construction costs.

Referring to FIGS. 1 and 2 , there is shown an embodiment of thegeothermal energy generating system 100. The main components of thegeothermal energy generating system 100 include fully cased downholewell loop 108, more specifically, the injection well 112, the firstlower lateral section 116, the multilateral connector 120 (also referredto herein as cross connect splitter 120, or multilateral junction 120),the second upper lateral section 124 and the production well 128. Thegeothermal energy generating system 100 further includes the pump 104and the turbine system 132 fluidly connected to the fully cased downholewell loop 108. More specifically pump 104 is connected to injection well112, and turbine system 132 is connected to production well 128. Thecooler 136 is fluidly connected between the turbine system 132 and thepump 104 closing the circuit for the single heat exchange loop.

As shown in FIG. 1 , an additional wellbore 140 is disposed adjacent thefully cased downhole well loop 108. This wellbore 140 (also referred toherein as connection wellbore 140, access wellbore 140, or sacrificialwellbore 140) is drilled to aid in the construction of fully caseddownhole well loop 108, however, it is not a part of the geothermalenergy generating system 100 and does not contribute towards the normaloperations of the geothermal energy generating system 100. Wellbore 140will be further described below with regards to the construction of thegeothermal energy generating system 100.

As can be seen in FIG. 1 , the direction of flow for the liquid workingfluid 204 is depicted by the solid lined arrows, and the direction offlow for the gaseous working fluid 208 is depicted by the dashed arrows.The details regarding the operation and phase change of the workingfluid 200 will be further described below.

While fully cased downhole well loop 108 is underground in thesurrounding rock formations 320, there are access points to fully caseddownhole well loop 108 located on the surface 316—more specifically, aninlet 112A located at an upper end 180 of the injection well 112 and anoutlet 128A located at an upper end 192 of the production end 128. Theinlet 112A is part of the injection well 112 and is configured to be theentry point on the surface 316 for the liquid working fluid 204. Theinlet 112A is surrounded by a surface casing 144. Similarly, theproduction well 128 includes an outlet 128A configured to be the exitpoint on the surface 316 for the gaseous working fluid 208. The outlet128A is surrounded by a surface casing 148, surface casing 148 beingsimilar to surface casing 144. In the current embodiment, except for theaforementioned inlet 112A, outlet 128A, and surface casings 144 and 148,the remainder of fully cased downhole well loop 108 is underground.Surface casings 144 and 148 are provided to isolate those segments ofinjection well 112 and production well 128 that are in proximity to thesurface 316, from fresh ground water and to prevent the escape ormigration of the working fluid 200 into the groundwater and/orenvironment. Particulars relating to the construction of the surfacecasings 144 and 148 are provided below. It will occur to a personskilled in the art that reference to rock formations 320 is not limitedto rocks, but may include any geological formation or combinations ofgeological formations that are underground.

Furthermore, in the current embodiment, the inlet 112A of the injectionwell 112 and the outlet 128A of the production well 128 are in proximityto each other. By locating the injection well 112 and production well128 in proximity to each other, geothermal energy generating systems 100may have a smaller footprint as compared to prior art systems on thesurface 316. In this embodiment, inlet 112A and outlet 128A are at adistance of 50 m away from each other, however, inlet 112A and outlet128A may at a distance between 7 m and 50 m. In addition, in a preferredembodiment, the distance between inlet 112A and outlet 128A would beless than either the length of upper lateral section 124 or the lengthof lower lateral section 116. In addition, a preferred embodiment of thesize of the footprint of the geothermal energy generating system 100 onthe surface, would be 22500 m² or 150 m×150 m. However, theconfiguration of the inlet 112A, the injection well 112, the outlet128A, the production well 128, the lower lateral section 116 and theupper lateral section 124 may not be limited based on the location ofthe inlet 112A and the outlet 128A. In other configurations, inlet 112Amay be at a significant distance from outlet 128A. In fact, in somealternate configurations of the fully cased downhole well loop 108,lower lateral section 116 and upper lateral section 124 may be at thesame depth. A person skilled in the art will recognize the differentpotential configurations of fully cased downhole well loop 108 and thedifferent potential placements of inlet 112A, injection well 112, outlet128A and production well 128.

The entirety of piping, wells and sections of fully cased downhole wellloop 108 are lined with cement 152 and cased with steel 156. Morespecifically, in the current embodiment, steel pipes are cemented withinthe wellbores of injection well 112 and production well 128, as part ofboth the lower and upper lateral sections 116 and 124, as part of themultilateral connector 120 and any connecting pieces between saidcomponents. The entire fully cased downhole well loop 108 is pressuretested to ensure that there are no leaks. The pressure test may bedefined as a hydraulic pressure test where the continuously joined steelcasing 156 is subjected to a minimum downhole pressure associated withthe greatest pressure upon which the fully cased downhole well loop 108may be subjected to. The greatest pressure that fully cased downholewell loop 108 may be subjected to may be a point along fully caseddownhole well loop 108 with the greatest depth, and is likely to bealong lower lateral section 116. In certain embodiments, to determinethe total downhole pressure for pressure testing, the following formulamay be used:Pressure at surface+Hydrostatic pressure

Where the hydrostatic pressure may be calculated as (Greatestdepth×Specific gravity of water).

For example if the deepest point along fully cased downhole well loop108 is along lower lateral section 116 at a 2500 m depth and thepressure applied at the surface is 2 MPa, where the specific gravity ofwater is 10 KPa/m, the total downhole pressure may be calculated byadding the surface and hydrostatic pressures, specifically in thisexample 2 MPa+(2500 m×10 KPa/m)=21 MP.

Pressure testing is performed using water, as in the event of anyleakage due to the high pressures, the leaking water does not create anypollution to the surrounding environment. The above formula using thehydrostatic pressure of water may be used for working fluids 200 wherethe specific gravity of water is greater than that of the specificgravity of working fluids 200. For example, the specific gravity ofpropane is less than that of water, and hence the formula above providesa higher pressure testing than what is required for propane as a workingfluid 200, ensuring safe operation of fully cased downhole well loop108. A person skilled in the art will recognize that if working fluid200 has a higher specific gravity than water, then the above formula maybe compensated by providing the specific gravity of said working fluid200, and then pressure-testing fully cased downhole well loop 108accordingly with water. Furthermore, in certain embodiments, thecalculated total downhole pressure for pressure testing above may beincreased to provide a safety factor, hence testing the fully caseddownhole well loop 108 with a higher pressure than the operationallimits for safety reasons. The pressures that fully cased downhole wellloop 108 are built to and pressure-tested to withstand are pressuresthat are not seen in prior art systems for the generation of energy fromgeothermal sources. This is due to the fact that the operationalpressures of working fluids in prior art systems tend to be much lowerthan those of working fluid 200 while flowing through fully caseddownhole well loop 108.

The pressure-tested fully cased downhole well loop 108 is able toreceive and convey working fluids 200 pressurized between 7 MPa and 31MPa. In an embodiment where working fluid 200 is a pentane,pressure-tested fully cased downhole well loop 108 may receive andconvey working fluid 200 between 7 MPa to 22 MPa. In a preferredembodiment, where the working fluid 200 is propane, pressure-testedfully cased downhole well loop 108 may receive and convey propaneworking fluid 200 between 7 MPa to 20 MPa.

During its operation, fully cased downhole well loop 108 may be capableof withstanding pressures of at least 7 MPa. In other embodiments,pressure-testing of fully cased downhole well loop 108 may includepressure-testing up to 31 MPa and may be designed to burst or fail at amaximum of 39 MPa.

Cement 152 is used to structurally secure steel 156 casing to thesurrounding rock formations 320, however in alternate embodiments,cement 152 may be mixed with other substances, such as the addition ofhematite to adjust the thermal conductivity of cement 152. While in thecurrent embodiment, cement 152 and steel 156 are used, it will occur toa person skilled in the art that any other materials may be used as abarrier, as long as they physically isolate the working fluid 200 fromthe exterior environment/rock formations 320, can undergo the pressurerequirements from both the working fluid 200 expanding and contractingwhile undergoing phase change, and as long as heat may conduct throughthe material.

The injection well 112 runs from the inlet 112A at the surface 316vertically downward underground a predetermined distance (or depth). Thepredetermined distance (or depth) may be determined on a site by sitebasis depending on geothermal gradient, rock thermal properties, geologyand geological composition of the targeted area. The geothermal gradientand rock thermal properties are variables to consider to determine thedepth and residence time at said depth to induce a phase change onworking fluid 200. Depth of injection well is chosen to achieve highrock temperature while minimizing drilling cost which increases withmany factors, including the depth and geological composition of rockformations 320. In the current embodiment, at its lower end 196, theinjection well 112 is joined to the lower lateral section 116 by acurved connecting piece 160. However, lower lateral section 116 may beconnected to injection well 112 and extend away from injection well 112at any location along injection well 112. The injection well 112 has adepth of between approximately 1000 m and 4000 m and production steelcasing 156 with an internal diameter of approximately 139 mm based onthe preferred working fluid temperature of 140° C. to be achieved.However, the injection well could be sized differently (i.e. be drilledto a different depth, whether at a greater depth or a shallower depth,and have a different diameter, whether larger or smaller), if requiredto suit a particular application. In the embodiment depicted in FIG. 1 ,the injection well 112 is shown extending vertically downward into theground. It will be appreciated that this need not be the case in everyembodiment. In some embodiments, the injection well could extenddownwardly into the ground at an angle from vertical.

In the preferred embodiment, the lower lateral section 116 can be seento be perpendicular to the injection well 112, and extend laterally awaytherefrom toward the XC connector 120. Moreover, the lower lateralsection 116 has a length of approximately 2000 m to 4000 m andproduction steel casing 156 with an internal diameter of approximately139 mm. In other embodiments, the lower lateral section 116 need not bedisposed laterally relative to the injection well 112 and could extendaway from the injection well 112 at an angle from lateral. It could alsobe sized differently.

Joining the lower lateral section 116 to the upper lateral section 124is the multilateral connector 120. Multilateral connector 120 mayinclude an XC splitter or other comparable connection device, which maybe connected between lower lateral section 116 and upper lateral section124 in a manner which ensures fully cased downhole well loop 108 may bepressure tested and may operate under pressure. For instance, the SAGDXC splitter multilateral system manufactured by Baker Hughes Company.The multilateral connector 120 is well known within the oil and gasindustry, and a person skilled in the art will recognize the varioustypes of multilateral connectors 120 available. However, the use ofmultilateral connector 120 within a geothermal energy generating systemis novel.

In the current embodiment, the upper lateral section 124 extendslaterally away from the multilateral connector 120 to join the lower end198 of the production well 128 via curved connecting piece 164. However,the upper lateral section 124 may join production well 128 at anylocation along production well 128. The upper horizonal section 124 isdisposed perpendicular to the production well 128. Moreover, the upperlateral section 124 has a length of approximately between 2000 m and4000 m and a production steel casing 156 with an internal diameter ofapproximately 139 mm. In other embodiments, the upper lateral section124 need not be disposed laterally relative to the production well 128and could extend toward the production well 128 at an angle fromlateral. It could also be sized differently.

In the embodiments where lower lateral section 116 is disposed laterallyrelative to injection well 112, and where upper lateral section 124 isdisposed laterally relative to the production well 128, both lateralsections 116 and 124 may be on the same vertical plane. However, it willoccur to a person skilled in the art that in alternate configurations,lateral sections 116 and 124 may be offset from each other in thevertical plane.

In this embodiment, the production well 128 does not extend as deeplyinto the ground as injection well 112. Preferably, the production wellhas a depth of 1000 m to 4000 m and a production steel casing 156 with adiameter of approximately 139 mm. However, the production well could besized differently (i.e. be drilled to a different depth, whether at agreater depth or a shallower depth, and have a different diameter,whether larger or smaller), if required to suit a particularapplication.

In the current embodiment, the length of the upper lateral section 116is shorter than that of the lower lateral section 116 due to thelocation of inlet 112A and outlet 128A. The lengths of each of the lowerlateral section 116 and upper lateral section 124 are selected based onthe amount of time that the working fluid 200 needs to remainunderground in contact with the heat-emitting rock formations 320 (i.e.residence time) and the flow rate of the working fluid 200. For example,if the working fluid 200 takes a longer time to heat up to undergo thephase change, whether due to the heat conductive properties of thesurrounding rock formations 320, well casing and lining of lateralsections 116 and 124, or due to the properties of the type of workingfluid 200 being used, then both lateral sections 116 and 124 may need tobe longer to accommodate the time that working fluid 200 needs to beheated to induce a phase change. Flow rate is another variable thatneeds to be taken into account, as a lower flow rate means that thedistance traveled over time is lower, and as such the length of lateralsections 116 and 124 may further be adjusted.

In a preferred embodiment, lower lateral section 116 runs deeper thanthe upper lateral section 124. Having two lateral sections 116 and 124at different depths may enhance thermal uptake from surrounding rockformations 320 as there may be less thermal interference between wells112 and 128. However, fully cased downhole well loop 108 is not limitedto this configuration. In alternate embodiments (not shown), the lateralsection returning to the production well 128 may be located deeper thanthe lateral section connected to the injection well 112. In addition, inalternate embodiments (not shown), both lateral sections 116 and 124 maybe at the same depth, but may be at an angle from each other, wheremultilateral connector 120 connects the two lateral sections 116 and 124from different angles. A person skilled in the art will recognize thedifferent potential configurations and lengths available for bothlateral sections 116 and 124, and also different potentialconfigurations for fully cased downhole well loop 108 overall.

As shown in FIGS. 1 and 2 , located on the surface 316, the pump 104 isfluidly connected to the inlet 112A of the injection well 112. The pump104 is operable to circulate the working fluid 200 through fully caseddownhole well loop 108 entering through the inlet 112A of injection well112 and proceeding underground.

Pump 104 is also configured to keep liquid working fluid 204 flowingthrough the entire single heat exchange loop by maintaining anappropriate flow rate of the working fluid 200. Flow rate (andaccordingly residence time) is determined by underground well loop toconduct enough heat energy to convert working fluid from a liquid to agas of sufficient temperature. In the current embodiment, the liquidworking fluid 204 received by pump 104 may be in the pressure range of500 kPag to 2000 kPag, and in the temperature range of 10° C. to 40° C.Pump 104 is configured to increase pressure from a range of 700 kPag to3000 kPag, and maintain a flow rate of 15 kg per second to 25 kg persecond. In a preferred embodiment, pump 104 is able to provide a liquidworking fluid 204 to the inlet 112A of injection well 112 atapproximately 1300 kPag in pressure and at a temperature ofapproximately 30° C. A preferred embodiment of pump 104 is the use of aliquid pump for thermodynamic efficiency. A liquid pump keeps parasiticenergy losses of the system to a minimum compared to the use ofmechanical gas compressors.

In other prior art geothermal systems, where the working fluid 200 comesinto contact with rock formations 320 due to the lack of casing, orwhere the working fluid 200 may pickup debris underground, pumps mayneed to be substantially more robust, and may need to handle abrasivematerials during operation. Furthermore, in prior art systems whereworking fluid 200 is water, pumps may need to handle water chemistrieswith scale forming characteristics during operation. In contrast, in thecurrent embodiment, as fully cased downhole well loop 108 is fully linedwith cement 152 and cased with steel 156, the working fluid 200 does notcome into contact with any rock formations 320, and is physicallyisolated from the environment. As such, the working fluid 200 does notpick up any debris, and remains as a clean homogenous fluid. This allowspump 104 to have a long service life with minimal maintenance hencesaving on procurement and operation costs and potentially allowing useof less robust or standard pump designs.

In a preferred embodiment, pump 104 may be a positive displacement typepump with a variable speed drive controller. Positive displacement pumptypes typically have high overall thermal efficiency and are able tomaintain desired outlet head when paired with a variable speed drive.Positive displacement pump types include plunger, gear or rotary vanetype pumps. However, as will be evident to a person skilled in the art,pump 104 may also be any type of pump that can handle the abovementionedpressures and temperatures. This may include, but is not limited tocentrifugal pumps or diaphragm pumps. A person skilled in the art willrecognize the different potential pumps that may be used based on theaforementioned pressure, flow rate and temperature specifications aswell as purchase and maintenance costs.

Also above ground is the turbine system 132 which is fluidly connectedto the upper end 192 of production well 128. The turbine system 132 mayinclude a turbine (not shown) with an output shaft connected to anelectrical power generator (not shown).

In the current embodiment, turbine system 132 is located in closeproximity to outlet 128A to prevent loss of heat from the gaseousworking fluid 208 as it travels along insulated pipes between outlet128A and turbine system 132. In other embodiments turbine system 132 maybe located further away form outlet 128A, but this tends not to bepreferred. While the exterior surface pipes carrying the gaseous workingfluid 208 to the turbine system may be insulated, heat and pressure maystill be lost, and as such travel distance and time is an importantconsideration. A person skilled in the art will be familiar with thestructure, configuration and operation of turbine system 132 and theassociated electric power generator such that they need not be describedherein.

In operation, the turbine system 132 receives the gaseous working fluid208 from the outlet 128A of production well 128, and the gaseous workingfluid 208 drives the turbine connected to the shaft. The mechanicalenergy generated by the rotation of the turbine is transferred to theelectric power generator, which can convert the mechanical energy intocommercially saleable electrical power. The electrical power may then berouted to a utility owned power grid for further distribution. In thecurrent embodiment, turbine system 132 may generate between 0.5 MW to 2MW in power. In a preferred embodiment, turbine system 132 may generateapproximately 1 MW in power.

Alternatively, if the power is not needed by the power grid, it may berouted towards batteries, other local loads, or may just be wasted forshort periods of time through an electrical resistive load bank. The useof a load bank to waste power allows equipment to be operated withoutlive connection to a power transmission line. This may be done forequipment testing and short periods of operational upsets (not shown).

In other embodiments, turbine system 132 may include either a turbineexpander, a piston expander, or a scroll expander. In a preferredembodiment a turbine expander(s) is used, where the turbine expander(s)may be radial or axial, where the radial turbine expander is connectedto one end of a shaft, and an electrical power generator connected tothe other end of the shaft. The expander output power shaft may connectdirectly or via a speed reduction gear box to the electrical powergenerator. The speed reduction gearbox may match the high speed (rpm)turbine wheel to the desired operating speed of the power generator. Thetype of expander and power generator will dictate if a gear box and typeof gear box is required. In alternative embodiments, turbine expandersmay also be volumetric type machines such as scroll, screw and vaneexpanders could also be used. The preferred output of the geothermalenergy generating system 100 is targeted to be over 1 MW produced byeach expander which makes high speed and compact turbo expanders apreferred embodiment as volumetric type expanders become large andexpensive for the targeted power output amount.

In another embodiment, multiple expanders may be used to maximize powergenerated. Use of multiple expanders is beneficial when trying to limitthe size of an expander for constructability or turn down efficienciesor to allow certain working fluids 200 to expand (flash) in stages,where the 1^(st) stage flash occurs in the primary expander, but energyexists in the working fluid that can be flashed again to a lowerpressure or in parallel to the first stage flash,

Where a turbo expander is included, the gaseous working fluid 208 may beexpanded as it passes through the conically contained radial turbine,hence reducing the pressure and the temperature of the gaseous workingfluid 208, while driving the turbine. Similar to that of the previousembodiment of turbine system 132, the rotation of the radial turbinecreates mechanical energy which is transferred to the electric powergenerator, where it is converted into commercially saleable electricalpower. The voltage from the power generators can be increased with apower step up transformer to match requirements of third partyelectrical power transmission lines for power sales to desired markets.

A low pressure gaseous working fluid 208 is output from the turbinesystem 132. In alternate embodiments, depending on the properties of theworking fluid 200 being used, the turbine system 132 may induce thereceived input gaseous working fluid 208 to partially change states intoa mixture of gas and liquid.

The cooler 136 (also referred to as condenser 136) is disposed between,and fluidly connected to, the turbine system 132 and the pump 104. Thecooler 136 is configured to receive the low pressure gaseous workingfluid 208 that is output from the turbine system 132, and to cool andcondense the low pressure gaseous working fluid 208 into a liquidworking fluid 204 through the use of a heat exchanger cooled by forceddraft air or through a mechanical chiller (not shown). In an embodimentwhere working fluid 200 leaving from turbine system 132 and received bycooler 136 is in a mixed state of both gas and liquid, the amount ofenergy used by cooler 136 may be reduced, as less work may be requiredto cool working fluid 200 to a liquid state. Alternatively, theresidence time of working fluid 200 within cooler 136 may also bereduced. A person skilled in the art will recognize that thespecifications of cooler 136 used may depend on the specifications ofworking fluid 200, the type of turbine system 132, and also the targetedfinal temperature and pressure of liquid working fluid 204 after exitingcooler 136.

As cooler 136 is fluidly connected to pump 104, the resultant liquidworking fluid 204 that is output from cooler 136 is returned to pump 104to be sent through fully cased downhole well loop 108 again. Preferably,the cooler 136 is a finned tubed type with forced draft ambient air usedas the coolant. This style of condenser cooler 136 is effective andrelatively inexpensive. However other embodiments could be used, such asbrazed aluminum plate style, tube style or other heat exchanger withworking fluid cooled by a segregated coolant.

Connecting pieces 168, 172, and 176 serve as additional pieces tocomplete the portion of single heat exchange loop above the surface 316.Specifically, connecting piece 168 serves as a connector to fluidlyconnect the outlet 128A of production well 128 to the inlet of turbinesystem 132. Similarly, connecting piece 172 fluidly connects the outletof turbine system 132 to the inlet of cooler 136. In addition,connecting piece 176 serves as a connector to fluidly connect the outletof cooler 136 with the inlet of pump 104.

As indicated above, fully cased downhole well loop 108 is fully linedand cased to physically isolate working fluid 200 from the rockformations 320 and environment. In the current embodiment, connectingpieces 168, 172, and 176 may be steel pipes, however in alternateembodiments, connecting pieces 168, 172 and 176 may be constructed ofother materials that do not leak, and can withstand the pressure andtemperature changes above ground. In a preferred embodiment, connectingpiece 168 between outlet 128A and turbine system 132 may also beinsulated to prevent heat loss prior to gaseous working fluid 208reaching turbine system 132. However, in alternate embodiments, allsurface connecting pieces 168, 172 and 176 may also be insulated toreduce loss of heat, which may lead to parasitic loss. Furthermore, thesingle heat exchange loop of the geothermal energy generating system100, which may include connecting pieces 168, 172 and 176 will bepressure tested to ensure that they do not leak when transporting theworking fluid 200 while the working fluid 200 undergoes pressurechanges. It will occur to a person skilled in the art that in connectingpieces 168, 172, and 176 may be of any shape or size depending on thelocations and the specifications of the working fluid 200, outlet 128A,turbine system 132, cooler 136, pump 104 and inlet 112A. It will alsooccur to a person skilled in the art that in embodiments wherecomponents are combined into a single unit, such as cooler 136 and pump104, that certain connecting pieces may not be needed and could beomitted.

As shown in FIG. 2 the geothermal energy generating system 100 may alsoinclude a storage vessel 188 (also referred to herein as storage tank188) to hold excess liquid working fluid 204 and to provide sufficientand consistent mass flow to pump 104. While not shown, other components,such as valves, heat exchangers, and other instruments may be used tooptimize the geothermal energy generating system 100. In alternateembodiments, filters or a filter separator may also be added to theoutlet 128A, upstream of turbine system 132, however, in the currentembodiment, filters are not essential if all piping is sufficientlyclean to remove manufacturing lubricants, mill scale, dirt and othercontaminants prior to commissioning of the turbine system 132, as with asingle working fluid 200 in a single heat exchange loop, there is littleto no debris or foreign particles expected during normal operation.

FIG. 3 depicts a geothermal energy generating system 100A which is analternate embodiment to that shown in FIGS. 1 and 2 . For convenience,like elements or structures shown in FIGS. 2 and 3 , are identified withthe same reference numerals. System 100A is similar in all materialrespects to the system 100 except that in geothermal energy generatingsystem 100A, a recuperator 184 (also referred to herein as heatexchanger 184) is provided. The recuperator 184 is disposed between, andconnected to the turbine system 132 and the cooler 136, and is alsoarranged between, and connected to, the pump 104 and the injection well112. The recuperator 184 is configured to minimize cooling load on thecooler 136 and preheat the liquid working fluid 204 before entering theinjection well 112 by cross exchanging heat from the warm low pressureturbine system 132 outlet gaseous working fluid 208 with the cold liquidworking fluid 204 from the outlet of pump 104. As warm low pressuregaseous working fluid 208 leaves turbine system 132 and travels throughrecuperator 184, it may transfer its heat to the cold liquid workingfluid 204 that is also going through recuperator 184 from the outlet ofpump 104 to the injection inlet 112. By providing heat from the lowpressure gaseous working fluid 208 leaving the turbine system 132, tothe cold liquid working fluid 204 heading towards injection well 112,heat energy is being saved and reused. The low pressure gaseous workingfluid 208 leaving turbine system 132 is headed towards cooler 136 tocondense and induce a phase change, and as such, transferring heatenergy from low pressure gaseous working fluid 208 prior to cooler 136reduces the time and energy needed for cooler 136 to condense thegaseous working fluid 208 into a liquid. Furthermore, the liquid workingfluid 204 headed towards injection well 112 is on its way underground tobe heated, and as such, pre-emptively heating the liquid working fluid204 may reduce the underground residence time required, hencepotentially allowing for shorter lateral sections 116 and 124, or forlateral sections 116 and 124 to be at a shallower depth. A personskilled in the art will recognize the potential of a recuperator 184 andthe potential configurations of a geothermal energy generating systemwith a recuperator 184.

In alternate embodiments, geothermal energy generating system 100 may beused for other purposes other than to generate electricity. For example,the work generated from the geothermal energy generating system 100 maybe used to effect other mechanical work. Alternatively, the workgenerated from the geothermal energy generating system 100 may be usedfor hydrogen generation.

Referring to FIG. 4 , there is shown a flowchart setting out the stepsof a method 400 of operating the geothermal energy generating system 100in accordance with an embodiment of the invention. The operation ofgeothermal energy generating system 100 occurs after the system has beenprimed and initiated, and follows a Rankine cycle (preferably an organicRankine cycle where an organic carbon-based working fluid is used). Anexample of priming the geothermal energy generating system 100 includesslowly circulating working fluid 200 through injection well 112, andallowing any residual liquid or gas (from either the constructionprocess or from the previous operation of the geothermal energygenerating system 100) to exit into a storage vessel to be collected.Once all residual liquid or gas has been removed, the working fluid 200may continue circulating through the geothermal energy generating system100 as part of its normal operation. As can be seen, method 400 is aloop. For ease of understanding, the process may be described as beingstarted at step 405 and ending at step 440 before starting the processagain at step 405.

As previously described, geothermal energy generating system 100 is asingle heat exchange loop with fully cased downhole well loop 108. Asfully cased downhole well loop 108 is fully cased and pressure tested,working fluid 200 may be a variety of liquids, gases or plasmas. Inalternate embodiments, working fluid 200 may be a carbon-basedcommercially available and environmentally friendly refrigerant or mixof refrigerants, such as 90% propane with 10% mole fraction ethane.Alternatively, working fluid 200 may be either a composition (aheterogenous working fluid 200) or a singular substance (a homogeneousworking fluid 200) of hydrocarbon, carbon dioxide, or ammonia. In apreferred embodiment where the geothermal energy generating system 100is an organic Rankine cycle, working fluid 200 may be propane. Withpropane, at a depth of 2000 m and a rock formation 320 temperature ofabout 160° C., a maximum temperature achieved by propane working fluid200 is about 140° C. Furthermore, propane working fluid 200 may becondensed into a liquid state working fluid 208 on a hot summer daywithout substantial cooling using ambient air forced across a fin tubecooler 136. Although propane is the working fluid 200 of choice, otherorganic (carbon-based), such as a hydrocarbon, or hydrocarbon blends mybe used. Hydrocarbon blends may be used to maximize working fluid 200return pressures. Hydrocarbon blends allow the working fluid 200 to betailored to specific depth and temperature conditions. For example, theaddition of ethane to a majority propane working fluid 200 would allowfor earlier wellbore flashing at a specific rock formation 320temperature. The early flashing would allow for an increased workingfluid 200 flow rate and therefore an increase in power generation.Another example is to blend hydrocarbon with butane to increase the heatcarrying capacity of the working fluid. By blending heavierhydrocarbons, the flash point/vaporization point along fully caseddownhole well loop 108 may be adjusted depending on the temperature ofthe surrounding rock formations 320. For example, the vaporization pointmay be adjusted based on the temperature of the surrounding rockformations 320 to be along the upper lateral section 124 or theproduction well 128, to maximize velocity of the working fluid 200, andminimize the friction of the working fluid 200 along the remainder ofthe pipe before exiting fully cased downhole well loop 108. A personskilled in the art will recognize the potential combinations of rockformation 320 temperature and different variations of hydrocarbon blendsto adjust the location of the vaporization point along fully caseddownhole well loop 108. While working fluid 200 may also be water, it ispreferably one of the abovementioned fluids, as the abovementionedsubstances have lower boiling points than water, requiring lessresidence time underground. Furthermore, the abovementioned fluids mayhave advantageous thermal capacities, and different phase transitionpoints, allowing for a more efficient system, and requiring lessresidence time underground in fully cased downhole well loop 108.

The below steps depict an embodiment where working liquid 200 ispropane. At step 405, the propane liquid working fluid 204 is conveyedunderground by flowing down injection well 112 and along lower lateralsection 116, multilateral connector 120 and upper lateral section 124.In order to reach injection well 112, liquid working fluid 204 is pumpedusing pump 104. In fact, working fluid 200 is circulated through thefully cased single heat exchange loop using pump 104. To ensure propercirculation, pump 104 will increase the pressure of liquid working fluid204 from 1080 kPag to 1300 kPag to be received by inlet 112A ofinjection well 112. In the current embodiment, where the working fluid200 is propane after departing pump 104 and prior to being received byinlet 112A, liquid working fluid 204 may have an approximate temperaturerange of about 10° C. to about 40° C., with a preferred temperature ofabout 20° C. and an approximate pressure range of about 1000 kPag toabout 2000 kPag, with a preferred pressure of about 1300 kPag. Once theliquid working fluid 204 has been received by inlet 112A, it flowsdownwards along vertical injection well 112.

When liquid working fluid 204 reaches the curved connecting piece 160,the direction of flow of liquid working fluid 204 transitions fromvertical to lateral and then continues along the lower lateral section116. Liquid working fluid 204 then reaches multilateral connector 120,where it will change direction to flow into the upper lateral section124 and continue flowing until the curved connection piece 164 adjacentto the lower end 198 of production well 128.

Towards the lower end 196 of injection well 112 and at the depths thatlower lateral section 116 is located, the surrounding environment androck formations 320 naturally conduct heat from the surrounding rockformations 320. As the liquid working fluid 204 flows downwards alonginjection well 112, when liquid working fluid 204 reaches a certaindepth where the rock formations 320 temperature exceeds the liquidworking fluid 204 temperature, heat is transferred from the surroundingenvironment or rock formations 320 to liquid working fluid 204 (at step405). The heat transfer may occur while liquid working fluid 204 isstill flowing downwards through injection well 112, and will continue tooccur while liquid working fluid 204 is flowing through connecting piece160 and lower lateral section 116. This heat may be conductivelytransferred from the surrounding environment to liquid working fluid 204through the cement lining 152 and steel casing 156. The depth thresholdthat the liquid working liquid 204 begins to receive heat, and henceincreases the temperature of liquid working fluid 204 is where thetemperature of the surrounding environment is greater than that ofliquid working fluid 204. This depth threshold depends on the geothermalgradient at the site and working fluid re-injection temperature. Theheat will continue to transfer to liquid working fluid 204 as the liquidworking fluid 204 flows through multilateral connector 120 and upperlateral section 124, thereby raising the temperature of liquid workingfluid 204 as it flows through said components.

Furthermore, as liquid working fluid 204 flows downwards in injectionwell 112, the pressure exerted on the liquid working fluid 204increases, as a consequence of the hydrostatic head (at step 415). Asliquid working fluid 204 reaches connecting piece 160 and lower lateralsection 116, the pressure of liquid working fluid 204 will continue toincrease as the fluid absorbs heat energy. There may be a slightreduction in pressure due to flow rate frictional losses in thewellbore, however liquid working fluid 204 will have a net increase inpressure. The approximate pressure of the liquid working fluid 204 uponreaching the lower end 196 of injection well 112/connecting piece 160 isapproximately 10,000 kPag, at the approximate depth of 2000 m as isprovided in the current embodiment. While the increase in pressureoccurs during a change in depth, the rate of the transfer of heat andconsequently the rate of temperature increase of liquid working fluid204 is dependent on depth, rock thermal conductivity, residence time androck formation 320 temperature. As such, the increase in temperaturewill continue while liquid working fluid 204 flows both downwards ininjection well 112 and flows laterally along lower lateral section 116.Both the transfer of heat and the increase in exertion of pressure isdepicted by step 415.

At step 420, at some point while liquid working fluid 204 is flowingthrough lower lateral section 116, connecting piece 160, multilateralconnector 120, connecting piece 164 and upper lateral section 124,liquid working fluid 204 will undergo a phase change from a liquid to agaseous state due to the liquid working fluid 204 reaching a boilingpoint from the heat and from the increased pressure (at step 415). Morespecifically, the rate of temperature increases until the liquid workingfluid 204 begins to vaporize, at which time the temperature will holdconstant until all liquid working fluid 204 transforms to a gaseousstate (gaseous working fluid 208), then the temperature will increaseagain as the vapor or gaseous working fluid 208 superheats. It willoccur to a person skilled in the art that the temperature and pressurerequired to vaporize the liquid working fluid 204 will change dependingon the specifications of the working fluid 200. In the currentembodiment where the working fluid 200 is propane it is vaporized at anapproximate temperature of 140° C., and at an approximate pressure of6250 kPag. In a preferred embodiment the phase change will occur withinthe upper lateral section 124 or the production well 128 to minimize theamount of friction between working fluid 200 and the remaining length ofcasing before working fluid 200 exits the fully cased downhole well loop108, hence maximizing velocity of working fluid 200, however it willoccur to a person's skilled in the art that the phase change to theworking fluid 200 may occur anywhere underground within fully caseddownhole well loop 108. It will occur to a person skilled in the artthat the location along the flow path of the working liquid in fullycased downhole well loop 108 will change depending on the configurationof fully cased downhole well loop 108, the lengths and depths ofcomponents within fully cased downhole well loop 108, the flow rate ofworking liquid 200, and the boiling point of the working fluid 200 aswell as rock formation 320 temperature, conduction rate from rockthrough the steel casing 156 and cement 152 into the working fluid 200.

At step 425, the gaseous working fluid 208 rises to the surface 316through production well 128, and exits fully cased downhole well loop108 at outlet 128A. As the gaseous working fluid 208 rises to thesurface 316, there will be a slight loss in pressure and temperature dueto the change in depth, however the temperature of the working fluid 200will be high enough to maintain the gaseous state of the working fluid208. The approximate temperature and pressure of gaseous working fluid208 at outlet 128A is between about 90° C. and about 110° C., with apreferred temperature of about 106° C., and between about 3000 kPag andabout 4000 kPag, with a preferred pressure of 3500 kPag. The gaseousworking fluid 208 is then conveyed towards turbine system 132 alongconnector piece 168.

As such, in the current embodiment, as the temperature of liquid workingfluid 204 is approximately 30° C. and about 1080 kPag at inlet 112A, andthe temperature of gaseous working fluid 208 is approximately 106° C.and about 3500 kPag at outlet 128A, the trip through fully caseddownhole well loop 108 by working fluid 200 increased its temperature byapproximately 76° C. and increased the pressure of working fluid 200 byapproximately 2170 kPag. In addition, in the current embodiment, theresidence time of working fluid 200 between entering inlet 112A andexiting outlet 128A is approximately 30 minutes. A person skilled in theart will recognize that the temperature difference and the residencetime is affected by multiple factors, including, but not limited to theconfiguration, depth and lengths of components of fully cased downholewell loop 108, as well as rock formation 320 temperature, rock thermalconductivity, conduction rate from rock through casing 156 and cement152 into the working fluid 200, and flow rate of working fluid 200.

In the current embodiment, where working fluid 200 is propane, thetemperature of the propane may range from an approximate temperature ofthe ambient surroundings/environment (ambient temperature) when enteringfully cased downhole well loop 108 at inlet 112A to 185° C. when exitingfully cased downhole well loop 108 at outlet 128A. The ambienttemperature may vary depending on the environment that the geothermalenergy generating system 100 is located in and may range between −43° C.to 45° C.

In the current embodiment, turbine system 132 is a turbo expander. Atstep 430, turbine system 132 receives the gaseous working fluid 208,where the gaseous working fluid 208 will drive the turbine (alsoreferred to herein as turbine wheel) thereby generating mechanicalenergy. As the turbine wheel is connected to the shaft, which isconnected to electrical generator, the mechanical energy is transferredto the electrical generator, which in turn, at step 435, converts themechanical energy into electrical energy. In the embodiment the gaseousworking fluid 208 is expanded by virtue of the shape of theexpander/valve and the pressure and temperature of gaseous working fluid208 is also lowered while spinning the radial turbine connecter to theshaft. The approximate pressure and temperature of the propane gaseousworking fluid 208 leaving turbine system 132 is be within the range ofabout 1500 kPag and about 63° C. and about 700 kPag and about 16° C. Inpreferred embodiments, the approximate pressure and temperature ofgaseous working fluid 208 may be easily condensed from gaseous workingfluid 208 to liquid working fluid 204 from the ambient air temperaturethrough cooler 136. The electrical energy generated by the electricalgenerator at step 435 is approximately 1 MW and may fluctuate dependingon cooler condensing pressure at ambient conditions. As such a reductionon the load required for cooler 136 to condense gaseous working fluid208 will increase the net electrical energy generated by the electricalgenerator. A person skilled in the art will recognize that any reductionon the parasitic loads, for example, the need to use energy for coolinggaseous working fluid 200, will increase the amount of electrical energygenerated, and increase the efficiency of the geothermal energygenerating system 100. It will occur to a person skilled in the art thatin certain embodiments, depending on the efficiency of turbine system132 and the specifications of the working fluid 200, the working fluid200 departing from turbine system 132 may be in a mixed state of bothgas and liquid.

At step 440, the gaseous working fluid 208 departing from turbine system132 may travel along connecting piece 172, and be received by cooler136. Cooler 136 may condense the gaseous working fluid 208 into a liquidstate. At the exit of cooler 136 the temperature and pressure of propaneliquid working fluid 204 may be 30° C. and 1080 kPag, but may fluctuatedepending on ambient air temperature and pressure.

Upon departure of cooler 136, liquid working fluid 204 may return topump 104 via connecting piece 176, where the liquid working fluid 204 isonce again circulated as can be seen by step 405.

Referring to FIG. 5 , there is shown a flowchart setting out the stepsof a method 400A for operating the geothermal energy generating system100A in accordance with an embodiment of the invention. For convenience,like reference numerals are used in FIGS. 4 and 5 to depict like steps.Method 400A is similar in all material respects to method 400 exceptthat there are additional steps 437 and 432 with relate to therecuperator 184.

Steps 405, 415, 420, 425, 430 and 435 are performed as described abovein the context of method 400 shown in FIG. 4 . Step 437 occurs afterstep 435, where the gaseous working fluid 208 transfers heat to aparallel pipe containing liquid working fluid 204 (which is received byliquid working fluid 204 as detailed below at step 442). By transferringheat via recuperator 184, the temperature of the gaseous working fluid208 drops and hence cooler 136 may require less energy to condensegaseous working fluid 208 in subsequent step 440. The temperature of thegaseous working fluid 208 after departure of recuperator 184 and priorto being received at cooler 136 is a decrease in temperature byapproximately 15° C.

Thereafter, step 440 is performed as described above in the context ofmethod 400 shown in FIG. 4 , that is, the gaseous working fluid iscondensed into liquid working fluid. Following step 440, the liquidworking fluid 204 enters recuperator 184 and receives heat therefrom, atstep 442. More specifically, recuperator 184 interacts with workingfluid 200 at two locations along the single heat exchange loop,specifically after turbine system 132 as gaseous working fluid 208, andafter pump 104 as liquid working fluid 204. The two pipes carryingworking fluid 200 are in close proximity while in recuperator 184,allowing the transfer of heat from the gaseous working fluid 208 to theliquid working fluid 204. As such, at step 442, the liquid working fluid204 receives heat from the gaseous working fluid 208 (which istransferred from gaseous working fluid 208 at step 437), thereby raisingthe temperature of liquid working fluid 204 before continuing onwards toinlet 112A. In this embodiment, the temperature of the liquid workingfluid 204 after leaving recuperator 184, and prior to arriving at inlet112A can be increased by as much as 10° C.

It will occur to a person skilled in the art that the approximatetemperature ranges and approximate pressure ranges provided above maychange depending on the configuration of the geothermal energygenerating system 100 or 100A, and may also change depending on thespecifications of the working fluid 200 being used and the ambient airtemperature. A person skilled in the art will also recognize thatdespite being provided approximate temperature ranges and pressureranges in the aforementioned embodiment where the preferred workingfluid 200 is a carbon-based commercially available and environmentallyfriendly refrigerant, geothermal energy generating system 100 willcontinue to operate despite the preferred working fluid 200 beingoutside the approximate temperature ranges and pressure ranges.

Referring to FIG. 6A, an embodiment of the geothermal energy generatingsystem 100-1 is shown, which includes two fully cased downhole wellloops, 108A and 108-2, where both two fully cased downhole well loops108-1 and 108-2 are connected to a single connection wellbore 140. Aswill be described further below, this facilities the construction asonly a single connection wellbore 140 needs to be drilled. Furthermore,by using a single connection wellbore 140, the footprint of thegeothermal energy generating system is further minimized. A personskilled in the art will recognize that the geothermal energy generatingsystem 100-1 is not limited to two fully cased downhole well loops, butmay any number of fully cased downhole well loops.

Referring to FIG. 6B, the components of the two fully cased downholewell loops 108-1 and 108-2 can be seen. The two fully cased downholewell loops 108-1 and 108-2 have similar components to those ofpreviously referenced fully cased downhole well loop 108 in FIGS. 1, 2,and 3 . As such, components within each of these two fully caseddownhole well loops 108-1 and 108-2 are similarly numbered to those offully cased downhole well loop 108 and appended with either an -1 or -2suffix to indicate the first or the second fully cased downhole wellloop 108-1 or 108-2. Given that the components are similar, thecomponents will not be described further.

In the embodiment 100-1, the two fully cased downhole well loops 108-1and 108-2 operate in the same manner as previously referenced embodimentof fully cased downhole well loop 108, however, after leaving therespective outlets 128A-1 and 128A-2 of production wells 128-1 and128-2, the two streams of gaseous working fluid 208 may be merged into asingle stream to be received by a single turbine system 132. As such,merging connecting piece 168-1 may be configured to allow for saidmerging of two streams of gaseous working fluid 208. Furthermore, asingle cooler 136 may receive the gaseous working fluid 208 exitingturbine system 132 to condense the gaseous working fluid 208 into liquidworking fluid 204. The liquid working fluid 204 may then be split intotwo streams using splitter connecting piece 176-1 to be received by pump104-1 and pump 104-2, where pump 104-1 may increase the pressure ofliquid working fluid 204 to be injected into injection well 112-1 andpump 104-2 may increase the pressure of liquid working fluid 204 to beinjected into injection well 112-2.

In using embodiment 100-1, the amount of components or equipmentrequired may be minimized as turbine system 132 and cooler 136 may beshared across fully cased downhole loops 108-1 and 108-2. This leads tofurther minimizing cost. Furthermore, the footprint and above groundsurface area is minimized as there is only a single turbine system 132and cooler 136 above ground, as opposed to a turbine system 132 and acooler 136 for each fully cased downhole well loop 108-1 and 108-2. Inaddition, scalability and economies of scale are inherent in the designof embodiment 100-1 as will be discussed below.

A person skilled in the art will recognize the modularity of turbinesystem 132, cooler 136 and pump 104. Specifically, a person skilled inthe art will recognize that any number of fully cased downhole wellloops 108 may be connected to a single turbine system 132, a singlecooler 136 and a single pump 104. Alternatively, any number of fullycased downhole well loops may be connected to multiple turbine systems132, a single cooler 136, and a single pump 104. Likewise, any number offully cased downhole well loops may be connected to a single turbinesystem 132, multiple coolers 136 and a single pump 104. Or as can beseen from embodiment 100-1, multiple pumps 104 may be used. As such, aperson skilled in the art will recognize the different combinations andvariations of fully cased downhole well loops 108, turbine systems 132,coolers 136 and pumps 104.

During commercial operation when numerous well loops are producing andselling power through a sales meter into an electrical powertransmission line there is desire to control power generated. Forexample, where 25 MW needs to be delivered to an electrical grid,twenty-five (25) fully cased downhole well loops 108 may be used. Anon/off power control scheme is used to export the optimal amount ofpower into the electrical grid on an hourly basis. The system mayelectronically monitor grid capacity and power demand then providefeedback to the facility process logic controller (PLC). In anembodiment where there is a single turbine system 132 connected to thetwenty-five (25) fully cased downhole well loops 108, the PLC will thenautomatically turn off pumps 104 and other rotating equipment and closeelectronically actuated well head valves to quickly “turn off”individual geothermal well loops. This on/off control system allows thefacility to change power output between 0 MW to 25 MW in 1 MWincrements. Alternatively, in an embodiment where there are twenty-five(25) turbine systems 132 connected to twenty-five (25) fully caseddownhole well loops 108, the PLC may then turn off pumps 104 for eachfully cased downhole well loops 108 and turn off turbine systems 132,allowing for the facility to provide power output between 0 MW to 25 MWin 1 MW increments.

This control scheme can also be used on a predetermined schedule. Theadvantages of the on/off control system is that is relatively simple todesign and operate and provides good power output control. This controlscheme can be used because the single closed loop system as shown inFIG. 6B where the working fluid only interacts with the undergroundreservoir through conduction. No reservoir fluids enter the geothermalloop and no well working fluid 200 enters the reservoir. All wellheating occurs through conductive heat transfer. For this reason, powerproduction can be rapidly changed by isolating working fluid 200 flowrate into the injection wells 112 which halts that well's electric powergeneration. Also, when a well is turned off it allows the undergroundrock to “recharge” through conductive heating and the fully caseddownhole well loop 108 will be able to produce increased power (comparedto steady state operation) when it is turned back on. A person skilledin the art will recognize the ability of the control scheme describedabove to control any number of fully cased downhole loops 108 andturbine systems 132.

Referring to FIG. 15 , there is shown a flowchart setting out the stepsof a method 1500 of constructing the fully cased downhole well loop 108of the geothermal energy generating system 100 in accordance with anembodiment of the invention. The construction of fully cased downholewell loop 108 uses drilling rigs to drill and connect two wellbores (theinjection well 112 and production well 128), and a third wellbore, aconnection wellbore 140, may be drilled and extended to provide aconnection point for injection well 112 and production well 128.

Step 1505 includes drilling connection wellbore 140, injection well 112,and lower lateral section 116 extending between the connection wellbore140 and injection well 112.

Two drilling rigs may be moved to and secured at separate surfacelocations. Referring to FIG. 7 , this would be positions 304 and 308.Positions 304 and 308 are at a predetermined distance apart of at leastthe length of the lateral sections 116 and 124 (as depicted in FIG. 1 )and at any offset distance required for the building angle in the welltrajectory. It will be evident to a person skilled in the art that thepositioning of the two drilling rigs in this case is based on theembodiment of fully cased downhole well loop 108 where the injectionwell 112, the production well 128, the lateral sections 116 and 124, andthe multilateral connector 120 being along the same vertical plane, andthat the positioning of the two drilling rigs may be adjusted based onthe location and configuration of the components of fully cased downholewell loop 108. In addition, while in the current embodiment two drillingrigs are used, it will occur to a person skilled in the art that anadditional third drilling rig may be used with changes to the sequenceof events.

The first drilling rig located at position 304 above the plannedconnection wellbore 140 will drill a 440 mm (17¼″) diameter hole to adepth of 650 m. The drilling mud/drilling fluid used may be anenvironmentally friendly freshwater gel system. Examples of the drillingmud include, but are not limited to, a bentonite clay as the gel, alongwith additives such as barium sulfate (Barite), calcium carbonate(chalk) or hematite. A person skilled in the art will recognize thedifferent drilling muds that may be used in association with thedrilling rigs. Surface casing 212 will be set in place with a diameterof 340 mm (13⅜″) and will be run to a depth of 650 m. The full lengthand circumference of surface casing 212 will be cemented to surface 316.Surface casing 212 is important to ensure the securing of plannedconnection wellbore 140 in place, prevent shallow formations fromsloughing into the wellbore, and to provide a base for the class 5blowout preventer described below.

The second rig located at position 308 at planned injection well 112will drill a 311 mm (12¼″) diameter hole to a depth of 650 m. Similar tothe drilling by the first rig located at position 304, the drilling mudof the second rig may be an environmentally friendly freshwater gelsystem. Surface casing 144 will be set in place with a diameter of 244mm (9⅝″) and will be run to a depth of 650 m. The full length andcircumference of surface casing 144 will be cemented to the surface 316.Similar to surface casing 212, the purpose of surface casing 144 is toensure the securing of planned injection well 112 in place, preventshallow formations from sloughing into the wellbore, and to provide abase for the class 5 blowout preventer described below. In addition,surface casing 144 is to ensure no leakage of any working fluids 200into the surrounding environment.

The cement casings used for both surface casing 144 and 212 willpreferably have a total calculated hole volume plus 50% excess ofthermal blend cement at 1860 kg/m³ (approximately 80 t total mass of thecement). The cement casing may then undergo a first preflush of 2.5 m³fresh water. The cement casing may then undergo a second preflush of 5m³ viscosified water weighted to 1200 kg/m³. An example of viscosifiedwater includes Optiflush™. A person skilled in the art will recognizeother forms or variations of viscosified water. The cement plug may thenbe dropped and displaced with fresh water.

Class 5 blowout preventers (not shown) may be installed in on or inproximity to surface casings 144 and 212. The class 5 blowout preventersare used to seal, control and monitor injection well 112 and connectionwellbore 140 to prevent blowouts. In the current embodiment, the class 5blowout preventers are pressure tested to a low pressure of 1,400 kPaand a high pressure of 35,000 kPA, where each pressure is tested over aduration of at least ten (10) minutes. Class 5 blowout preventers mayalso be pressure tested depending on formation pressures and anyrelevant regulatory requirements.

Drilling of holes for injection well 112 and connection wellbore 140will be directionally controlled with a directionally controlleddrilling assembly with measure while drilling (“MWD”) surveys tomaintain target accuracy. Specifically, the first drilling rig atposition 304 will drill a 311 mm (12¼″) diameter intermediate hole (notshown), through surface casing, to a predetermined depth. Initially, theconnection wellbore 140 will be drilled vertically, and thendirectionally drilled to achieve a 90-degree inclination at landingpoint 228 in proximity to lower end 216 of connection wellbore 140. Thislanding point 228 will be in the geothermal target formation, which islocated at a depth with the targeted temperature. In the currentembodiment, connection wellbore 140 is drilled with an oil-based mudsystem to minimize washout and protect wellbore integrity. However, thedrilling mud system used may be dependent on the area and historicaldrilling problems of the area. A person skilled in the art willrecognize the different potential drilling mud systems that may be used.

An intermediate thermal casing 236 with a diameter of 244 mm (9⅝″) willbe run the total depth of connection wellbore 140, and the intermediatethermal casing 236 may be cemented to the surfaces of the surroundingrock formations 320. The intermediate thermal casing 236 may thenundergo a first preflush of 5 m³ viscosified water, where theviscosified water is weighted to provide greater wellborepressure/hydrostatic pressure than that of the formation pressure tomaintain an overbalanced wellbore. The intermediate thermal casing 236may then undergo a second preflush of 5 m³ scavenger weighted to 1450kg/m³, or higher to maintain an overbalanced wellbore. An overbalancedwellbore will prevent the formation of gas or fluid from entering thewellbore and rising to the surface. The cement is then filled/providedinto intermediate thermal casing 236 with a thermolite cement at totalcalculated hole volume plus 20% excess (approximately 75 t). The tailcement is then provided with a gastight cement at 20% (approximately 45t). The inner diameter of the cement is then displaced with fresh waterto create the hollow wellbore, leaving the outer diameter cemented tothe rock formations 320.

The volumes and blends of the cement may be adjusted depending onhistorical well data, formation pressures and regional regulatoryisolation requirements for certain formations to prevent crossflowcontaminations.

Intermediate thermal casing 236 may be secured at wellhead/inlet 232utilizing a speed head or an additional wellhead section to set slips.Slips (also referred to herein as anchors) may be set with intermediatethermal casing 236 in full tension to hold the intermediate thermalcasing 236 inside surface casing 212. In certain embodiments, the class5 blowout preventer on surface casing 212 may have to be disassembledfor the installation of the slips. Once reassembled, the class 5 blowoutpreventer may be pressure tested again to the same pressures andspecifications to confirm integrity of the class 5 blowout preventerafter re-assembly, however with intermediate thermal casing 236 presentin connecting well 140.

A gyroscopic wireline survey tool may be deployed in connecting wellbore140. The gyroscopic wireline survey tool will allow continuous surveyingfrom vertical to horizontal and point of refusal. The gyroscopicwireline survey tool provides well geometry with an extremely high levelof accuracy, and gives exact coordinates of connecting wellbore 140 toassist in intersecting with injection well 112.

The first drilling rig will then drill a 222 mm (8¾″) diameter main holethrough intermediate thermal casing 236 to provide a 200 m diameter openhole. Similar to above, the drilling of the main hole by first drillingrig may use an oil-based mud system.

After the main hole has been drilled, the directionally controlleddrilling assembly will be removed from the well. A magnetic tool willthen be lowered into wellbore to the end of the 200 m open hole section.An example of the magnetic tool is the Lodestone™ provided by ScientificDrilling. The magnetic tool is an active ranging system built forintentional wellbore intersections. It can be used in conjunction withall MWD systems. The sensor of the magnetic tool may be deployed inconnection wellbore 140 and magnetic sub may be deployed ondirectionally controlled drilling assembly in injection well 112. Theresulting magnetic field provides accurate ranging for the intersectionalong horizontal section 116 between the connection wellbore 140 sideand the injection well 112 side.

The second rig will drill a 222 mm (8¾′) main hole, through surfacecasing 144, to a predetermined depth. In a preferred embodiment, thepredetermined depth is between 2300 m and 2500 m, however the depth mayvary depending on the preferred temperature or geothermal targetformation. Initially, the well may be drilled vertically, and thendirectionally drilled to achieve a 90-degree inclination at landingpoint 224, where landing point 224 is in proximity to the lower end 196of injection well 112. The landing point 224 will be in the geothermaltarget formation. Similar to the first drill rig drilling the main holeof connection wellbore 140, the drilling of the main hole of injectionwell 112 may be drilled with an oil-based mud system. The drillingassembly may then be removed from well. The gyroscopic wireline surveytool may then be deployed in injection well 112 to provide thecoordinates of injection well 112 to assist in intersection withconnection well 140. A new directionally controlled drilling assembly,complete with magnetic tool (as previously described Lodestone™ package)will be lowered into wellbore.

To intersect between the two ends of lower lateral section 116, drillingwill continue laterally from the injection well 112 and landing point224 end of lower lateral section 116 in direction of connection wellbore140. The magnetic tool and will facilitate the intersection of the twowellbores. Once the two ends of lower lateral section 116 haveintersected at an intersection point 240, both directionally controlleddrilling assemblies may be removed from their respective wellbores.

At step 1510 (shown in FIG. 15 ), production steel casing 156 isinstalled in injection well 112 and lower lateral section 116.

Referring to FIG. 8 , production steel casing 156 with a diameter 139 mm(5½″) may be installed along injection well 112 and along lower lateralsection 116 from landing point 224 to the intersection point 240.Specifically, the production steel casing 156 may extend from the inlet112A of the injection well 112 at the surface 316, to 50 m into theintermediate thermal casing 236 of connecting wellbore 140. Thelowermost end section 248 of production steel casing 156 will have aconnection/seal assembly (not shown) to be used to make a pressuretested connection with multilateral connector 120. In the currentembodiment, the connection/seal assembly is a polished bore receptacle.The polished bore receptacle will be completed with a Bakercentralized/reversed sealbore extension and anchor seal assembly latchprofile (not shown).

Custom built steel centralizers (not shown) may also be attached toexterior of casing 156, prior to cementing. Centralizers are typicallydesigned to lift casing 156 from the bottom of lower lateral section116, thus allowing the cement to encircle casing 156 completely. Thecustom built elongated centralizers may also be used to provideincreased conductivity (as they are made of steel) between formationheat and steel body of casing 156 directly through the cement 152. Aspreviously stated, hematite additions may be also added to cement 152 tooptimize conductivity.

At step 1515 (shown in FIG. 15 ), an isolation packer 252 and acementing stage tool 256 are installed, and production steel casing 156of injection well 112 and lower lateral section 116 are cemented inplace.

Referring to FIG. 9 , the isolation packer 252 is a rubber element,which can be expanded to create an impermeable seal between the outerdiameter of the production steel casing 156 and the inner diameter ofthe intermediate thermal casing 236. This will prevent cement fromentering remaining intermediate casing and causing a blockage inconstruction well 140. In a preferred embodiment, two isolation packers252 may be used to increase the integrity of seal packers (not shown).

The cementing stage tool 256 will be opened (which also creates an innerdiameter plug at the end of the production steel casing 156 to preventcement from entering intermediate thermal casing 236 from connectionwell 140). The production steel casing 156 from injection well 112 maythen be cemented to the surface of the surrounding rock formations 320.

Cementing production steel casing 156 includes first circulatinginjection well 112 clean of all drill cuttings. A first dart may then bedropped into injection well 112 from the surface to inflate theisolation packer 252 and to open cementing stage tool 256 to allowcement to be circulated around the outer diameter of production steelcasing 156. Injection well 112 then undergoes a first preflush of 5 m³viscosified water, where similar to previous flushings the viscosifiedwater is weighted to maintain an overbalanced wellbore. Injection well112 then undergoes a second preflush of 5 m³ scavenger, the scavengerweighted to 1450 kg/m³ to maintain the overbalance within injection well112. The cement is then filled/provided into intermediate thermal casing236 with a thermolite cement at total calculated hole volume plus 20%excess (approximately 62 t). The tail cement is then provided with agastight cement at 20% excess (approximately 98 t). The cement is thendisplaced with fresh water. A person skilled in the art will recognizethat similar to the abovementioned drilling procedures for connectingwell 140, that volumes, blends and intervals of cement and preflushingmay be adjusted based on historical data of the geographical locationsand formations, formation pressures and regional regulatory isolationrequirements for certain formations to prevent crossflow contaminations.A second dart is also dropped into the injection well 112 from thesurface and will land in cementing stage tool 256 (which acts as a checkvalve), which will close cementing ports, effectively blocking cementfrom flowing back up injection well 112.

Production steel casing 156 will be set in tension with automatic slipsin a casing bowl, where the casing bowl allows the production steelcasing 156 to be bolted to the class 5 blowout preventer.

The second drilling rig will pick up milling assembly including the114.3 mm (4½″) bit, mud motor and 73 mm (2⅞″) diameter drill pipe. Tripin hole and mill out cementing stage tool 256 and float equipment toallow the unrestricted flow of working fluid 200. Debris is also clearedfrom connecting wellbore 140, lower lateral section 116, connectingpiece 160 and injection well 112 by circulating inhibited water returnsdown injection well 112, through connecting piece 160 and lower lateralsection 116, and up connecting wellbore 140 to the surface 316.

At step 1520 (shown in FIG. 15 ), a two-part whipstock 260 is installed,the access hole to allow the intersection of planned production well 128and upper lateral section 124 to lower lateral section 116 is drilled,and initial holes for production well 128 are drilled.

Referring to FIG. 10 , the two-part whipstock 260 (also referred toherein as whipstock 260) is installed within lower lateral section 116in proximity to isolation packer 252, between the landing point 228 andthe isolation packer 252. The whipstock 260 includes an upper section(spoon), which forces the pineapple mill (not shown) to cut a diamondshaped window 264 (also referred to herein as milled window 264 andbridging hole 264) through intermediate casing 236. Whipstock 260 alsoincludes a lower section (not shown) which includes a guide and anchor(not shown) which may be set permanently in intermediate casing. Theguide allows drilling and completion assemblies to be forced out throughwindow, in addition to a 139.7 (5½″) diameter hole through the center ofthe guide. This allows completion assemblies to be diverted through tolower section of wellbore A person skilled in the art will recognize theuse of whipstocks and their uses in creating wellbore junctions.

Whipstock and milled window 264 will allow a second wellbore to bedrilled in the geothermal target formation, from connecting wellbore140.

The second drilling rig may then move to position 312 above plannedproduction well 128. The second drilling rig will drill a 311 mm (12¼″)diameter hole to a depth of 650 m. Similar to the initial holes forinjection well 112 and connecting wellbore 140, drilling mud may be anenvironmentally friendly freshwater gel system. Surface casing 148 maybe set in place with a diameter of 244 mm (9⅝″) and will be run to adepth of 650 m and the full length of surface casing 148 may be cementedto the surface of surrounding rock formations 320.

The cement casing used in association with surface casing 148 willpreferably have a volume plus 50% of thermal cement at 1860 kg/m3(approx. 45 t). The cement casing may then undergo a first preflush of2.5 m³ fresh water. The cement casing may then undergo a second preflushof 5 m³ viscosified water weighted to 1200 kg/m3. The cement plug maythen be dropped and displaced with fresh water.

Similar to the setting in place of surface casing 144, class 5 blowoutpreventer may be installed on or in proximity to surface casing 148.Class 5 blowout preventer may then be pressure tested under the sameconditions and with the same considerations as those of class 5 blowoutpreventers for injection inlet 112.

At step 1525 (shown in FIG. 15 ), production well 128 and upper lateralsection 124 are drilled, and upper lateral section 124 and lower lateralsection 116 are intersected.

Referring to FIG. 11 , the first drilling rig may drill a 222 mm (8¾″)diameter main hole, through intermediate thermal casing 236 to providean additional 200 m of open hole. In the current embodiment, main holemay be drilled with an oil-based mud system. The directionallycontrolled drilling assembly may be removed from connection wellbore140. The magnetic tool will then be lowered into connection wellbore 140to the end of the 200 m open hole leading from connector piece 160. Themagnetic tool may be deployed in connecting well 140 and the magneticsub may be deployed on directional assembly in production well 128.

The second drilling rig will drill a 222 mm (8¾′) diameter main hole,through surface casing 148, to a predetermined depth. Initially, theproduction well 128 will be drilled vertically, and then directionallydrilled to achieve a 90-degree inclination at landing point 272. Landingpoint 272 will be in geothermal target formation. Similar to previousdrilling procedures, production well 128 may be drilled with anoil-based mud system. The directionally controlled drilling assembly maybe removed from production well 128 and the gyroscopic wireline surveytool may be deployed in production well 128. The gyroscopic wirelinesurvey tool may provide coordinates of production well 128 to assist inthe intersecting with connecting wellbore 140. A new drilling assembly,complete with magnetic tool may be lowered into production well 128.Drilling will continue in the direction of connecting wellbore 140. Themagnetic tool and the magnetic sensor will facilitate the intersectionof the two wellbores. Once connecting wellbore 140 and production well128 have intersected, both directionally controlled drilling assembliesmay be removed from wellbores.

The upper section of whipstock (spoon) is removed, leaving lower sectionof whipstock 260 inside intermediate thermal casing 236 of connectingwellbore 140. The lower whipstock section (guide and anchor) allows themultilateral connector 120 with a short section of casing ordirectionally controlled drilling assemblies to be diverted out thewindow into the open hole section connected to production well 128.Additionally, the guide has a 139 mm (5½″) diameter hole through thecenter of whipstock 260. This allows the multilateral connector 120 withcertain outer diameters to be lowered beneath the whipstock and connectwith production casing on injection well 112. By adjusting outerdiameters of the completion assemblies, the installer can ensure properassemblies enter correct wellbore.

At step 1530 (shown in FIG. 15 ), the production steel casing 156 isinstalled in the production well 128 and the upper lateral section 124.

Referring to FIG. 12 , production steel casing 156 with a 139 mm (5½″)diameter will be installed in intersected wellbores from connectingwellbore 140. The production steel casing 156 may extend from productionwell 128 at the surface 316 at outlet 128A, to within approximately 20 mof the intermediate thermal casing window 264 in connecting wellbore140. The lowermost end section 276 of production steel casing 156 mayhave a connection/seal assembly similar to that of lowermost end section248, specifically in the current embodiment connection/seal assembly maybe a polished bore receptacle with Baker centralized/reversed seal boreextension and anchor seal assembly latch profile.

At step 1535 (shown in FIG. 15 ), multilateral connector 120 isinstalled and connected between upper lateral section 124 and lowerlateral section 116. Fully cased downhole well loop 108 is then pressuretested.

Referring to FIG. 13 , two dummy trips into injection well 128 areconducted. The first trip is conducted with a polished bore locator sealassembly, where there is no latch, with an outer diameter greater than139.7 mm (5½″) to tag receptacle in production well 128 to verify exactdepth for spacing. The second trip is conducted with a polished borelocator seal assembly, where there is no latch, with an outer diameterless than 139.7 mm (5½″) to tag receptacle in injection well 112 toverify exact depth for spacing. This process allows for the exact depthmeasurements and distances between the access well 140, the injectionwell 112 and the production well 128. Multilateral connector 120 maythen be constructed with appropriate spacing to connect injection well112 and production well 128.

Multilateral connector 120 may be lowered into connecting well 140,(utilizing drill pipe for landing operation) to connect injection well112 and production well 128. The multilateral connector 120 will be madeup of two different “legs”, with each leg designed to ensure andfacilitate entry into a specific well (either injection well 112 orproduction well 128), and create a pressure tested connection with theproduction steel casing 156 in each of injection well 112 and productionwell 128. One leg 292 will include a polished bore locator seal assemblywith centralized shear type protective shroud, with an outer diameterless than 139 mm. This will allow polished bore location seal assemblyto be lowered through window guide and connect with polished borereceptacle of production steel casing on injection well 112. The secondleg 296 of multilateral connector 120 is of the same design except theouter diameter will be greater than 139 mm, forcing the polished borelocator seal assembly with centralized shear type protective shroud outthe milled window and connecting it with production steel casing 156 viapolished bore receptacle on production well 128. The second leg 296 mayalso include a pin/shear activated sleave to protect seals from frictiondamage through window 280 and open hole section.

The multilateral connector 120 offers full mechanical and hydraulicisolation support of the junction area with re-entry capabilities. Themultilateral connector 120 is designed to accommodate re-entry tie-inson steam-assisted gravity drainage applications. It is typically runwith a full-length liner on one attachment, with the second attachmentproviding a pressure tested seal with existing lateral. The multilateralconnector 120 serves to provide the junction point of injection well 112and production well 128 utilizing the connecting wellbore 140 as theentry point.

Connecting wellbore 140 may be used for the construction of multiplepairs of injection wells 112 and production wells 128. By adjustinglateral length of lateral section of connecting wellbore 140, multiplejunctions and “sets” of geothermal wells could be added to system.

Once connection of multilateral connector 120 to injection well 112 andproduction well 128 is complete, circulation can be established fromproduction well 128, through production steel casing 156, and throughdrill pipe to the surface 316 on connecting wellbore 140. A valve can beclosed at the surface 316 of connecting wellbore 140, and entireassembly and sealed connections on injection well 112 and productionwell 128 can be pressure tested. Production well 128 may be initiallycirculated to clean production well 128 and injection well 112 of anyremaining cuttings.

With the circulation able to be established, a pressure test (known tothose skilled in the art) may be performed on the entire fully caseddownhole well loop 108.

At step 1540 (shown in FIG. 15 ), an isolation packer 284 and acementing stage tool 288 are installed, and production steel casing 156of production well 128 and upper lateral section 124 are cemented inplace.

Referring to FIG. 13 , upon completion of successful circulation andpassing of pressure tests, the cementing stage tool 288 may be opened.Cementing stage tool 288 also creates an inner diameter plug at the endof production steel casing to prevent cement from entering intermediatethermal casing 236 from connecting wellbore 140 and injection well 112.The production steel casing 156 from production well 128 will be fulllength cemented to the surface of the surrounding rock formations 320 atproduction well 128. This includes entire open hole section and innerdiameter of surface casing on production well 128.

Cementing production steel casing 156 follows the same procedure as isdescribed above, including dropping a first dart to inflate isolationpacker 284 and open cement staging tool 288, pre-flushing the productionsteel casing 156 first with viscosified water, and then with scavenger,filling with thermolite cement, providing tail cement, displacing thecement with fresh water, and then dropping the second dart. Theproduction steel casing 156 will be set in tension with automatic slipsin the casing bowl.

The second drilling rig will pick up milling assembly consisting of a114.3 mm (4½″) bit, mud motor and 73 mm (2⅞″) diameter drill pipe.Subsequently, trip in hole and mill out cementing stage tool 288 andfloat equipment. In addition, all debris is cleared from the wellbore,by initially circulating returns to production well 128 and a finalcirculation up production steel casing 156 of injection well 112.

In the alternative, cementing stage tools 256 and 288 may be milled outin injection well 112 and production well 128 along with multilateralconnector 120 connections to lateral sections 116 and 124 aftercementing. This can be completed with a drilling rig and a jointed drillpipe, or a coiled tubing unit. In both cases, a 114 mm (4½″) drill bitmay be used to mill out cementing stage tools 256 and 288 and verify thefull gauge inner diameter of production steel casing 156. Additionally,mill outs would clean production steel casing 156 inner diameter of anydebris and excess cement. Coil tubing could also be used to mill outboth production well 128 and injection well 112.

A wireline retrievable isolation plug may be installed in connectingwellbore 140 inside intermediate thermal casing 236, above multilateralconnector 120. A positive and negative pressure test may then beconducted.

Once testing has been successfully performed, the geothermal energygenerating system 100 is ready to be operated in accordance with themethod steps set out in FIGS. 4 and 5 .

The construction of the geothermal energy generating system 100leverages known technologies and methods in wellbore construction in thefield of oil and gas, but applies said technologies and methods in anovel and inventive manner for the generation and production of energyfrom geothermal sources.

Although the foregoing description and accompanying drawings to specificpreferred embodiments of the present invention as presently contemplatedby the inventor, it will be understood that various changes,modifications and adaptations, may be made without departing from thespirit of the invention.

The invention claimed is:
 1. A system for generating energy fromgeothermal sources, the system comprising: an injection well extendingunderground into a rock formation, the injection well having an upperend and a lower end; a production well extending underground into therock formation in proximity to the injection well, the production wellhaving an upper end and lower end; a first lateral section connected toand extending away from a location along the injection well; a secondlateral section connected to and extending away from a location alongthe production well; and the first and second lateral sections connectedwith a multilateral connector, each of the first and second lateralsections having a length that is greater than the distance between theupper ends of the injection well and the production well; each of theinjection well, the production well, the first and second lateralsections being cased in steel and cemented in place within the rockformation; the injection well, the first lateral section, themultilateral connector, the second lateral section and the productionwell cooperating with each other to define a pressure-tested downholewell loop within the rock formation and in a heat transfer arrangementtherewith, the pressure-tested downhole well loop being configured toreceive a working fluid capable of undergoing phase change betweenliquid and gas within the pressure-tested downhole well loop as a resultof heat transferred from the rock formation; a pump fluidly connected tothe injection well, the pump being configured to circulate the workingfluid through the pressure-tested downhole well loop; a turbine systemfluidly connected to the production well, the turbine system beingoperable to convert mechanical energy generated from the flow of workingfluid, into electricity; a cooler fluidly connected between the pump andthe turbine system for cooling the working fluid; and an injection wellsurface casing surrounding an inlet of the injection well, the injectionwell surface casing extending partially above the injection well surfaceand configured to prevent the escape of the working fluid into the rockformation.
 2. The system of claim 1 further comprising a production wellsurface casing surrounding an outlet of the production well, theproduction well surface casing extending partially above the productionwell surface and configured to prevent the escape of the working fluidinto the rock formation.
 3. The system of claim 1, wherein the injectionwell includes an inlet, and the production well includes an outlet, theinlet and the outlet being located on the surface in proximity to eachother, the inlet being at a distance between 7 m and 50 m from theoutlet.
 4. The system of claim 1, wherein the system has an above groundsurface area of 22500 m².
 5. The system of claim 1, wherein the workingfluid is a homogeneous working fluid.
 6. The system of claim 1, whereinthe working fluid is a heterogenous working fluid.
 7. The system ofclaim 1, wherein the injection well has a depth of between 1000 m and4000 m.
 8. The system of claim 1, wherein the first lateral section hasa length of between 2000 m to 4000 m.
 9. The system of claim 1, whereinthe second lateral section has a length of between 2000 m to 4000 m. 10.The system of claim 1, wherein the production well has a depth ofbetween 1000 m to 4000 m.
 11. The system of claim 1, wherein the firstlateral section is longer than the second lateral section, and whereinthe first lateral section is at a lower depth than that of the secondlateral section.
 12. The system of claim 1, wherein the first lateralsection is a the same depth as the second lateral section, the firstlateral section extending away from the lower end of the injection wellat a first angle, and the second lateral section extending away from thelower end of the production well at a second angle.
 13. The system ofclaim 1, wherein in operation the pressure-tested downhole well loopbeing configured to receive fluids pressurized between 7 MPa and 31 MPa.14. The system of claim 1, wherein the pressure-tested downhole wellloop is capable to withstand pressures of at least 7 MPa.
 15. The systemof claim 1, wherein the pump is a positive displacement type pump with avariable speed drive controller.
 16. The system of claim 15, wherein thepositive displacement type pump is selected from the group consisting ofplunger type pumps, gear type pumps and rotary vane type pumps.
 17. Thesystem of claim 1, wherein the turbine system includes a turbineexpander.
 18. The system of claim 1, wherein the turbine system iscapable of generating between 0.5 to 2 MW of output power.
 19. Thesystem of claim 1, wherein the cooler is using ambient air as a coolant.20. The system of claim 1 further comprising a storage tank, the storagetank connected between the cooler and the pump, and being configured tohold the excess working fluid.
 21. The system of claim 1, wherein theworking fluid is selected from the group consisting of a refrigerant, ahydrocarbon-based fluid, ammonia, carbon dioxide, and water.
 22. Thesystem of claim 21, wherein the hydrocarbon-based working fluid isselected from the group consisting of propane, ethane, pentane, butane,and hydrocarbon blend.
 23. The system of claim 1, wherein the workingfluid is propane.
 24. The system of claim 1 further comprising arecuperator with a first flow through connected between the turbinesystem and the cooler, and a second flow through connected between thepump and the injection well, the recuperator being configured totransfer heat from the first flow through to the second flow through.25. The system of claim 1 further comprising an access well having alateral segment, wherein the multilateral connector is positioned withinthe lateral segment of the access well.
 26. The system of claim 25further comprising: wherein the injection well is a first injectionwell, the production well is a first production well, the multilateralconnector is a first multilateral connector, the pressure-testeddownhole well loop is a first pressure-tested downhole well loop and thepump is a first pump; a second injection well extending underground intothe rock formation, the second injection well having an upper end and alower end; a second production well extending underground into the rockformation in proximity to the second injection well, the secondproduction well having an upper end and lower end; a third lateralsection connected to and extending away from a location along the secondinjection well; a fourth lateral section connected to and extending awayfrom a location along the second production well; and the third andfourth lateral sections connected with a second multilateral connector,each of the third and fourth lateral sections having a length that isgreater than the distance between the upper ends of the second injectionwell and the second production well; each of the second injection well,the second production well, the third and fourth lateral sections beingcased in steel and cemented in place within the rock formation; thesecond injection well, the third lateral section, the secondmultilateral connector, the fourth lateral section and the secondproduction well cooperating with each other to define a secondpressure-tested downhole well loop within the rock formation and in aheat transfer arrangement therewith, the second pressure-tested downholewell loop being configured to receive the working fluid capable ofundergoing phase change between liquid and gas within the secondpressure-tested downhole well loop as a result of heat transferred fromthe rock formation; a second pump fluidly connected to the secondinjection well, the second pump being configured to circulate theworking fluid through the second pressure-tested downhole well loop; thesecond production well fluidly connected to the turbine system, theturbine system being configured to receive the working fluid from thefirst production well of the first pressure-tested downhole well loopand the second production well of the second pressure-tested downholewell loop; the cooler fluidly connected to both the first pump connectedto the first injection well, and the second pump connected to the secondinjection well; and the second multilateral connector of the secondpressure-tested downhole well loop being positioned within the lateralsegment of the access well at a location spaced apart from the firstmultilateral connector.
 27. The system of claim 26, wherein the firstinjection well includes a first inlet, the first production wellincludes a first outlet, the second injection well includes a secondinlet, and the second production well includes a second outlet, thesecond inlet and the second outlet being located on the surface inproximity to each other, the second inlet being at a distance between 7m and 50 m from the second outlet.
 28. The system of claim 27, whereinthe first inlet and the second inlet being located on the surface inproximity to each other, the first inlet being at least a distance of 20m from the second inlet.
 29. The system of claim 27, wherein the firstoutlet and the second outlet being located on the surface in proximityto each other, the first outlet being at least a distance of 20 m fromthe second outlet.
 30. The system of claim 27, wherein the system has anabove ground surface area of 45000 m².
 31. A method of generating energyfrom geothermal sources comprising: providing a pressure-tested downholewell loop extending underground into a rock formation, thepressure-tested downhole well loop including: an injection well, aproduction well in proximity to the injection well, a first lateralsection connected to the injection well, a second lateral sectionconnected to the production well, a multilateral connector connectingthe first lateral section and the second lateral section; each of theinjection well, the production well, the first and second lateralsections being cased in steel and cemented in place within the rockformation, the first and second lateral sections having a length that isgreater than the distance on the surface between the injection well andthe production well; conveying a working fluid through thepressure-tested downhole well loop, the working fluid being received bythe injection well in a liquid state; while conveying the working fluidthrough the pressure-tested downhole well loop, transferring heat fromthe surrounding rock formations to the liquid working fluid and exertingpressure on the liquid working fluid; inducing a phase change in theworking fluid from a liquid state to a gaseous state, the working fluidexiting the production well in a gaseous state; converting themechanical energy generated from the flow of the gaseous working fluid,into electricity; cooling the working fluid and inducing a phase changein the working fluid to a liquid state; returning the working fluid tothe injection well; and providing an injection well surface casingsurrounding an inlet of the injection well, the injection well surfacecasing extending partially above the injection well surface andconfigured to prevent the escape of the working fluid into the rockformation.
 32. The method of claim 31, wherein conveying the workingfluid through the pressure-tested downhole well loop includes pumpingthe working fluid.
 33. The method of claim 31, wherein exerting pressureon the liquid working fluid includes exerting between 7 MPa and 31 MPaon the liquid working fluid.
 34. The method of claim 31, wherein thestep of converting the mechanical energy generated from the flow of thegaseous working fluid into electricity generates between 0.5 to 2 MW ofoutput power.
 35. The method of claim 31, wherein the step of coolingthe working fluid and inducing a phase change in the working fluid iscooled using a cooler.
 36. The method of claim 31 further comprisingstoring excess working fluid in a storage tank.
 37. The method of claim31, wherein the working fluid is a homogenous working fluid.
 38. Themethod of claim 31, wherein the working fluid is a heterogenous workingfluid.
 39. The method of claim 31, wherein the working fluid is selectedfrom the group consisting of a refrigerant, a hydrocarbon-based fluid,ammonia, carbon dioxide, and water.
 40. The method of claim 39, whereinthe hydrocarbon-based working fluid is selected from the groupconsisting of propane, ethane, pentane, butane, and hydrocarbon blend.41. The method of claim 31, wherein the working fluid is propane. 42.The method of claim 41, wherein the propane being received by theinjection well having a temperature of between 10° C. and 40° C. and apressure of between 1000 kPag and 2000 kPag.
 43. The method of claim 42,wherein the propane being received by the injection well having atemperature of 20° C. and a pressure of 1300 kPag.
 44. The method ofclaim 41, wherein inducing a phase change in the propane from a liquidstate to a gaseous state occurs when the propane reaches a temperatureof 140° C. and a pressure of 6250 kPag.
 45. The method of claim 44,wherein inducing a phase change in the propane from a liquid state to agaseous state occurs in one of the second lateral section and theproduction well.
 46. The method of claim 41, wherein the propane exitingthe production well in a gaseous state having a temperature of between90° C. and 110° C. and a pressure of between 3000 kPag and 4000 kPag.47. The method of claim 46, wherein the propane exiting the productionwell in a gaseous state having a temperature of 106° C. and a pressureof 3500 kPag.
 48. The method of claim 41, wherein while conveying theworking fluid through the pressure-tested downhole well loop, thetemperature of the propane increases by 76° C. and the pressure of thepropane increases by 2170 kPag.
 49. The method of claim 41, whereinafter converting the mechanical energy generated from the flow of thegaseous working fluid into electricity, the propane having a temperatureof between 16° C. and 63° C. and a pressure of between 700 kPag and 1500kPag.
 50. The method of claim 41, wherein cooling the working fluidcools the propane to a temperature of 30° C. and a pressure of 1080kPag.
 51. The method of claim 41 further comprising transferring heatfrom the working fluid in a first region to the working fluid in asecond region using a recuperator, the working fluid in the first regionoccurring between the steps of converting the mechanical energygenerated from the flow of the gaseous working fluid and cooling theworking fluid, the working fluid in the second region occurring betweenthe steps of conveying the working fluid through the pressure-testeddownhole well loop and the working fluid being received by the injectionwell in the liquid state.
 52. A system for generating energy fromgeothermal sources, the system comprising: a first injection well and asecond injection well extending underground into a rock formation, eachof the first and second injection well having an upper end and a lowerend; a first production well and a second production well extendingunderground into the rock formation, each of the first and secondproduction well in proximity to both the first and second injectionwell, each of the first and second production well having an upper endand lower end; a first lateral section connected to and extending awayfrom a location along the first injection well; a second lateral sectionconnected to and extending away from a location along the firstproduction well; a third lateral section connected and extending awayfrom a location along the second injection well; a fourth lateralsection connected to and extending away from a location along the secondproduction well; the first and second lateral sections connected with afirst multilateral connector, each of the first and second lateralsections having a length that is greater than the distance between theupper ends of the first injection well and the first production well;the third and fourth lateral sections connected with a secondmultilateral connector, each of the third and fourth lateral sectionshaving a length that is greater than the distance between the upper endsof the second injection well and the second production well; each of thefirst and second injection wells, the first and second production wells,the first, second, third and fourth lateral sections being cased insteel and cemented in place within the rock formation; the firstinjection well, the first lateral section, the first multilateralconnector, the second lateral section and the first production wellcooperating with each other to define a first pressure-tested downholewell loop within the rock formation, the second injection well, thethird lateral section, the second multilateral connector, the fourthlateral section and the second production well cooperating with eachother to define a second pressure-tested downhole well loop within therock formation, being in a heat transfer arrangement with the rockformation each of the first and the second pressure-tested downhole wellloop being configured to receive a working fluid capable of undergoingphase change between liquid and gas as a result of heat transferred fromthe rock formation; a first pump fluidly connected to the firstinjection well, the first pump being configured to circulate the workingfluid through the first pressure-tested downhole well loop; a secondpump fluidly connected to the second injection well, the second pumpbeing configured to circulate the working fluid through the secondpressure-tested downhole well loop; a turbine system fluidly connectedto the first and second production wells, the turbine system beingoperable to convert mechanical energy generated from the flow of workingfluid, into electricity; a cooler fluidly connected between the firstand second pumps and the turbine system, the cooler being operable tocool the working fluid received from the turbine system and to providethe cooled working fluid to both the first and second pumps; and thefirst and second pressure-tested downhole well loop located in proximityto each other.
 53. A system for generating energy from geothermalsources, the system comprising: an injection well extending undergroundinto a rock formation, the injection well having an upper end and alower end; a production well extending underground into the rockformation in proximity to the injection well, the production well havingan upper end and lower end; a first lateral section connected to andextending away from a location along the injection well; a secondlateral section connected to and extending away from a location alongthe production well; and the first and second lateral sections connectedwith a multilateral connector, each of the injection well, theproduction well, the first and second lateral sections being cased insteel and cemented in place within the rock formation; the injectionwell, the first lateral section, the multilateral connector, the secondlateral section and the production well cooperating with each other todefine a pressure-tested downhole well loop within the rock formationand in a heat transfer arrangement therewith, the pressure-testeddownhole well loop being configured to withstand a pressure of at least7 MPa and receive a working fluid capable of undergoing phase changebetween liquid and gas within the pressure-tested downhole well loop asa result of heat transferred from the rock formation; a pump fluidlyconnected to the injection well, the pump being configured to circulatethe working fluid through the pressure-tested downhole well loop; aturbine system fluidly connected to the production well, the turbinesystem being operable to convert mechanical energy generated from theflow of working fluid, into electricity; a cooler fluidly connectedbetween the pump and the turbine system for cooling the working fluid;and an injection well surface casing surrounding an inlet of theinjection well, the injection well surface casing extending partiallyabove the injection well surface and configured to prevent the escape ofthe working fluid into the rock formation.